Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2016 | Oct. 26, 2016 | |
Entity Information [Line Items] | ||
Entity Registrant Name | CALPINE CORP | |
Entity Central Index Key | 916,457 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Entity Common Stock, Shares Outstanding | 359,087,745 |
Consolidated Condensed Statemen
Consolidated Condensed Statements of Operations - USD ($) shares in Thousands, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Operating revenues: | ||||
Commodity revenue | $ 2,063 | $ 1,888 | $ 5,199 | $ 4,933 |
Mark-to-market gain (loss) | 287 | 55 | (79) | 89 |
Other revenue | 5 | 5 | 14 | 14 |
Operating revenues | 2,355 | 1,948 | 5,134 | 5,036 |
Operating expenses: | ||||
Commodity expense | 1,294 | 943 | 3,197 | 2,754 |
Mark-to-market (gain) loss | 178 | 130 | (57) | 95 |
Fuel and purchased energy expense | 1,472 | 1,073 | 3,140 | 2,849 |
Plant operating expense | 215 | 200 | 741 | 732 |
Depreciation and amortization expense | 161 | 166 | 503 | 484 |
Sales, general and other administrative expense | 33 | 33 | 106 | 100 |
Other operating expenses | 18 | 16 | 55 | 56 |
Total operating expenses | 1,899 | 1,488 | 4,545 | 4,221 |
(Income) from unconsolidated investments in power plants | (6) | (6) | (16) | (18) |
Income from operations | 462 | 466 | 605 | 833 |
Interest expense | 158 | 159 | 472 | 471 |
Interest (income) | (1) | (1) | (3) | (3) |
Debt modification and extinguishment costs | 0 | 0 | 15 | 32 |
Other (income) expense, net | 8 | 1 | 21 | 8 |
Income before income taxes | 297 | 307 | 100 | 325 |
Income tax expense (benefit) | (4) | 28 | 17 | 32 |
Net income (loss) | 301 | 279 | 83 | 293 |
Net income attributable to the noncontrolling interest | (6) | (6) | (15) | (11) |
Net income attributable to Calpine | $ 295 | $ 273 | $ 68 | $ 282 |
Basic earnings per common share attributable to Calpine: | ||||
Weighted average number of shares outstanding, basic | 354,215 | 355,443 | 353,929 | 365,053 |
Earnings per share, basic | $ 0.83 | $ 0.77 | $ 0.19 | $ 0.77 |
Weighted Average Number of Shares Outstanding, Diluted | 356,352 | 357,676 | 355,980 | 368,219 |
Earnings Per Share, Diluted | $ 0.83 | $ 0.76 | $ 0.19 | $ 0.77 |
Consolidated Condensed Stateme3
Consolidated Condensed Statements of Comprehensive Income - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ 301 | $ 279 | $ 83 | $ 293 |
Cash flow hedging activities: | ||||
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income | 7 | (16) | (33) | (32) |
Reclassification adjustment for loss on cash flow hedges realized in net income | 11 | 12 | 33 | 36 |
Foreign currency translation gain (loss) | (3) | (11) | 9 | (19) |
Income tax expense | 0 | 0 | 0 | 0 |
Other comprehensive income (loss) | 15 | (15) | 9 | (15) |
Comprehensive income | 316 | 264 | 92 | 278 |
Comprehensive (income) attributable to the noncontrolling interest | (8) | (5) | (15) | (11) |
Comprehensive income attributable to Calpine | $ 308 | $ 259 | $ 77 | $ 267 |
Consolidated Condensed Balance
Consolidated Condensed Balance Sheets - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents ($135 and $118 attributable to VIEs) | $ 561 | $ 906 |
Accounts receivable, net of allowance of $5 and $2 | 801 | 644 |
Inventories | 518 | 475 |
Margin deposits and other prepaid expense | 178 | 137 |
Restricted cash, current ($141 and $132 attributable to VIEs) | 210 | 216 |
Derivative assets, current | 959 | 1,698 |
Current assets held for sale | 452 | 0 |
Other current assets | 36 | 19 |
Total current assets | 3,715 | 4,095 |
Property, plant and equipment, net ($3,758 and $4,062 attributable to VIEs) | 13,069 | 13,012 |
Restricted cash, net of current portion ($14 and $11 attributable to VIEs) | 15 | 12 |
Investments in power plants | 80 | 79 |
Long-term derivative assets | 323 | 313 |
Assets Held-for-sale, Not Part of Disposal Group | 0 | 130 |
Other assets ($63 and $119 attributable to VIEs) | 786 | 1,040 |
Total assets | 17,988 | 18,681 |
Current liabilities: | ||
Accounts payable | 590 | 552 |
Accrued interest payable | 144 | 129 |
Debt, current portion ($164 and $166 attributable to VIEs) | 197 | 221 |
Derivative liabilities, current | 991 | 1,734 |
Other current liabilities | 392 | 412 |
Total current liabilities | 2,314 | 3,048 |
Debt, net of current portion ($3,013 and $3,096 attributable to VIEs) | 11,623 | 11,716 |
Long-term derivative liabilities | 436 | 473 |
Other long-term liabilities | 344 | 277 |
Total liabilities | 14,717 | 15,514 |
Commitments and contingencies (see Note 11) | ||
Stockholders’ equity: | ||
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding | 0 | 0 |
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 359,609,997 and 356,755,747 shares issued, respectively, and 359,080,056 and 356,662,004 shares outstanding, respectively | 0 | 0 |
Treasury stock, at cost, 529,941 and 93,743 shares, respectively | (7) | (1) |
Additional paid-in capital | 9,618 | 9,594 |
Accumulated deficit | (6,237) | (6,305) |
Accumulated other comprehensive loss | (170) | (179) |
Total Calpine stockholders’ equity | 3,204 | 3,109 |
Noncontrolling interest | 67 | 58 |
Total stockholders’ equity | 3,271 | 3,167 |
Total liabilities and stockholders’ equity | $ 17,988 | $ 18,681 |
Consolidated Condensed Balance5
Consolidated Condensed Balance Sheets (Parenthetical) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Cash and cash equivalents ($135 and $118 attributable to VIEs) | $ 561 | $ 906 |
Accounts receivable, net of allowance of $5 and $2 | 5 | 2 |
Restricted cash, current ($141 and $132 attributable to VIEs) | 210 | 216 |
Property, plant and equipment, net ($3,758 and $4,062 attributable to VIEs) | 13,069 | 13,012 |
Restricted cash, net of current portion ($14 and $11 attributable to VIEs) | 15 | 12 |
Other assets ($63 and $119 attributable to VIEs) | 786 | 1,040 |
Debt, current portion ($164 and $166 attributable to VIEs) | 197 | 221 |
Debt, net of current portion ($3,013 and $3,096 attributable to VIEs) | $ 11,623 | $ 11,716 |
Preferred Stock, Par or Stated Value Per Share | $ 0.001 | $ 0.001 |
Preferred Stock, Shares Authorized | 100,000,000 | 100,000,000 |
Preferred Stock, Shares Issued | 0 | 0 |
Preferred Stock, Shares Outstanding | 0 | 0 |
Common Stock, Par or Stated Value Per Share | $ 0.001 | $ 0.001 |
Common Stock, Shares Authorized | 1,400,000,000 | 1,400,000,000 |
Common Stock, Shares, Issued | 359,609,997 | 356,755,747 |
Common Stock, Shares, Outstanding | 359,080,056 | 356,662,004 |
Treasury Stock, Shares | 529,941 | 93,743 |
Variable Interest Entity, Primary Beneficiary [Member] | ||
Cash and cash equivalents ($135 and $118 attributable to VIEs) | $ 135 | $ 118 |
Restricted cash, current ($141 and $132 attributable to VIEs) | 141 | 132 |
Property, plant and equipment, net ($3,758 and $4,062 attributable to VIEs) | 3,758 | 4,062 |
Restricted cash, net of current portion ($14 and $11 attributable to VIEs) | 14 | 11 |
Other assets ($63 and $119 attributable to VIEs) | 63 | 119 |
Debt, current portion ($164 and $166 attributable to VIEs) | 164 | 166 |
Debt, net of current portion ($3,013 and $3,096 attributable to VIEs) | $ 3,013 | $ 3,143 |
Consolidated Condensed Stateme6
Consolidated Condensed Statements of Cash Flows - USD ($) $ in Millions | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | ||
Cash flows from operating activities: | |||
Net income | $ 83 | $ 293 | |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation and amortization(1) | [1] | 672 | 519 |
Non Cash Gains Losses On Extinguishment Of Debt | 15 | 1 | |
Deferred income taxes | 15 | 12 | |
Mark-to-market activity, net | [2] | 21 | 4 |
(Income) from unconsolidated investments in power plants | (16) | (18) | |
Return on consolidated investments in power plants | 19 | 23 | |
Stock-based compensation expense | 23 | 19 | |
Other Noncash Income (Expense) | 1 | (1) | |
Change in operating assets and liabilities, net of effect of acquisition: | |||
Accounts receivable | (168) | 42 | |
Derivative instruments, net | (71) | (44) | |
Other assets | (75) | (199) | |
Accounts payable and accrued expenses | 46 | (200) | |
Other liabilities | 102 | 108 | |
Net cash provided by operating activities | 667 | 559 | |
Cash flows from investing activities: | |||
Purchases of property, plant and equipment | (337) | (411) | |
Purchase of Granite Ridge Energy Center | (526) | 0 | |
Decrease (increase) in restricted cash | 2 | (31) | |
Other | 20 | (8) | |
Net cash used in investing activities | (841) | (450) | |
Cash flows from financing activities: | |||
Borrowings under First Lien Term Loans | 556 | 1,592 | |
Repayment of CCFC Term Loans and First Lien Term Loans | (1,220) | (1,622) | |
Borrowings under Senior Unsecured Notes | 0 | 650 | |
Borrowings under First Lien Notes | 625 | 0 | |
Repurchase of First Lien Notes | 0 | (147) | |
Repayments of project financing, notes payable and other | (98) | (102) | |
Financing costs | (27) | (17) | |
Stock repurchases | 0 | (510) | |
Shares withheld for tax obligations on share-based awards | (5) | (11) | |
Other | (2) | 0 | |
Net cash used in financing activities | (171) | (167) | |
Net decrease in cash and cash equivalents | (345) | (58) | |
Cash and cash equivalents, beginning of period | 906 | 717 | |
Cash and cash equivalents, end of period | 561 | 659 | |
Cash paid during the period for: | |||
Interest, net of amounts capitalized | 421 | 465 | |
Income taxes | 10 | 19 | |
Supplemental disclosure of non-cash investing and financing activities: | |||
Change in capital expenditures included in accounts payable | (4) | (17) | |
Capital Lease Obligations Incurred | $ 0 | $ 9 | |
[1] | Includes amortization recorded in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts. | ||
[2] | In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. |
Basis of Presentation and Summa
Basis of Presentation and Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2016 | |
Accounting Policies [Abstract] | |
Summary of significant accounting policies | Basis of Presentation and Summary of Significant Accounting Policies We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our retail customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants. Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2015 , included in our 2015 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts. Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates. Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows. The table below represents the components of our restricted cash as of September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 December 31, 2015 Current Non-Current Total Current Non-Current Total Debt service $ 39 $ 7 $ 46 $ 28 $ 8 $ 36 Construction/major maintenance 34 4 38 50 2 52 Security/project/insurance 134 2 136 136 — 136 Other 3 2 5 2 2 4 Total $ 210 $ 15 $ 225 $ 216 $ 12 $ 228 Business Interruption Proceeds — We record business interruption insurance proceeds when they are realizable and recorded approximately $9 million and $17 million of business interruption proceeds in operating revenues during the three and nine months ended September 30, 2016 , respectively. We did not record any business interruption proceeds during the three and nine months ended September 30, 2015 . Property, Plant and Equipment, Net — At September 30, 2016 and December 31, 2015 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): September 30, 2016 December 31, 2015 Depreciable Lives Buildings, machinery and equipment $ 16,478 $ 16,294 3 – 46 Years Geothermal properties 1,376 1,319 13 – 58 Years Other 228 208 3 – 46 Years 18,082 17,821 Less: Accumulated depreciation 5,719 5,377 12,363 12,444 Land 119 120 Construction in progress 587 448 Property, plant and equipment, net $ 13,069 $ 13,012 Capitalized Interest — The total amount of interest capitalized was $5 million and $3 million for the three months ended September 30, 2016 and 2015 and $14 million and $12 million for the nine months ended September 30, 2016 and 2015 , respectively. Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments) We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value. In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material. When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material. We did not record any material impairments during the three and nine months ended September 30, 2016 and 2015 . New Accounting Standards and Disclosure Requirements Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard is effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We are currently assessing the potential effect the revenue recognition standard may have on our financial condition, results of operations or cash flows. Consolidation — In February 2015, the FASB issued Accounting Standards Update 2015-02, “Amendments to the Consolidation Analysis.” The standard amends the consolidation model used in determining whether a reporting entity should consolidate the financial results of certain of its partially- and wholly-owned subsidiaries. All of our subsidiaries are subject to reevaluation under the revised consolidation model. Specifically, the amendments (i) modify the evaluation of whether limited partnerships and similar legal entities are voting interest entities or VIEs, (ii) eliminate the presumption that a general partner should consolidate the financial results of a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and (iv) provide an exception for certain types of entities. This standard became effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period. We adopted Accounting Standards Update 2015-02 in the first quarter of 2016 which did not have a material effect on our financial condition, results of operations or cash flows. Debt Issuance Costs — In April 2015, the FASB issued Accounting Standards Update 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” The standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, which is consistent with the presentation of debt discounts. In August 2015, the FASB issued Accounting Standards Update 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” which allows an entity to present debt issuance costs associated with a line-of-credit arrangement as an asset regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The standards became effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We retrospectively adopted Accounting Standard Updates 2015-03 and 2015-15 in the first quarter of 2016 which resulted in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion on our Consolidated Condensed Balance Sheet at December 31, 2015 . Cloud Computing Arrangements — In April 2015, the FASB issued Accounting Standards Update 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” The standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard became effective for fiscal years beginning after December 15, 2015, including interim periods. We adopted Accounting Standards Update 2015-05 in the first quarter of 2016 which did not have a material effect on our financial condition, results of operations or cash flows. Inventory — In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” The standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. We are currently assessing the potential effect this standard may have on our financial condition, results of operations or cash flows. Stock-Based Compensation — In March 2016, the FASB issued Accounting Standards Update 2016-09, “Improvements to Employee Share-Based Payment Accounting.” The standard applies to several aspects of accounting for stock-based compensation including the recognition of excess tax benefits and deficiencies and their related presentation in the statement of cash flows as well as accounting for forfeitures. The standard also requires that shares withheld to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees be presented as a financing activity in the statement of cash flows. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and allows for prospective, retrospective or modified retrospective adoption, depending on the area covered in the standard, with early adoption permitted. We early adopted Accounting Standards Update 2016-09 in the third quarter of 2016. The cumulative-effect adjustment to accumulated deficit for all excess tax benefits not previously recognized as of the beginning of the year is substantially offset by a corresponding change in the valuation allowance. The implementation of Accounting Standards Update 2016-09 did not have a material effect on our financial condition, results of operations or cash flows. Statement of Cash Flows — In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and allows for retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. |
Acquisition (Notes)
Acquisition (Notes) | 9 Months Ended |
Sep. 30, 2016 | |
Business Combinations [Abstract] | |
Mergers, acquisitions and dispositions disclosures | Acquisitions and Divestitures Acquisition of NAES On October 9, 2016, we announced that we entered into an agreement, through our indirect, wholly-owned subsidiaries Calpine Energy Services Holdco II, LLC and Calpine Energy Financial Holdings, LLC, to purchase NAES and a swap contract from Noble Americas Gas & Power Corp. and Noble Group Limited for approximately $800 million plus approximately $100 million of net working capital estimated at closing. We expect to recover approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. NAES is a commercial and industrial retail electricity provider with customers in 18 states in the U.S. including California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this large direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing us a valuable sales channel for reaching a much greater portion of the load we seek to serve. The transaction is expected to close in the fourth quarter of 2016, subject to federal regulatory approval and approval of the shareholders of Noble Group Limited, and will be funded with a combination of cash on hand and debt financing. Acquisition of Granite Ridge Energy Center On February 5, 2016, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), from Granite Ridge Holdings, LLC, for approximately $500 million , excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market. Beginning operations in 2003, Granite Ridge Energy Center is located in Londonderry, New Hampshire and features two combustion turbines, two heat recovery steam generators and one steam turbine. We funded the acquisition with a combination of cash on hand and our 2023 First Lien Term Loan obtained in the fourth quarter of 2015, and the purchase price was primarily allocated to property, plant and equipment. The pro forma incremental effect of Granite Ridge Energy Center on our results of operations for each of the three and nine months ended September 30, 2016 and 2015 is not material. Acquisition of Champion Energy On October 1, 2015, we, through our indirect, wholly-owned subsidiary Calpine Energy Services Holdco, LLC, completed the purchase of Champion Energy Marketing, LLC from a subsidiary of Crane Champion Holdco, LLC, which owned a 75% interest, and EDF Trading North America, LLC, which owned a 25% interest, for approximately $240 million , excluding working capital adjustments. The addition of this well-established retail sales organization is consistent with our stated goal of getting closer to our end-use customers and provides us a valuable sales channel for directly reaching a much greater portion of the load we seek to serve. The purchase price was funded with cash on hand and any excess of the purchase price over the fair values of Champion Energy’s assets and liabilities was recorded as goodwill; however, the goodwill we recorded as a result of this acquisition was immaterial. The purchase price allocation was finalized during the third quarter of 2016 which did not result in any material adjustments. Sale of Mankato Power Plant On October 26, 2016, we, through our indirect, wholly-owned subsidiaries, New Steamboat Holdings, LLC and Mankato Holdings, LLC, completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and 345 MW expansion project under advanced development located in Minnesota, to Southern Power Company, a subsidiary of Southern Company, for $396 million , excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We expect to use the proceeds from the sale to fund pending acquisitions and for other corporate purposes. We expect to record a gain on sale of assets, net of approximately $160 million during the fourth quarter of 2016, and our federal and state NOLs will almost entirely offset the projected taxable gain from the sale. Sale of South Point Energy Center On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million , approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. The natural gas-fired, combined-cycle plant is located on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and features a summer peaking capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration. Sale of Osprey Energy Center We executed an asset sale agreement in the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million , excluding working capital and other adjustments, which will be consummated in January 2017 upon the conclusion of a PPA with a term of 27 months . The sale has received FERC and state regulatory approvals and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities. Assets Held for Sale The assets of South Point Energy Center, which is part of our West segment, and the assets of Osprey Energy Center and Mankato Power Plant, including the expansion project at our Mankato Power Plant, which are part of our East segment, are reported as current assets held for sale on our Consolidated Condensed Balance Sheet at September 30, 2016 . The table below presents the components of our current assets held for sale at September 30, 2016 (in millions): September 30, 2016 Assets: Current assets $ 12 Property, plant and equipment, net 401 Other long-term assets 39 Total current assets held for sale $ 452 |
Variable Interest Entities and
Variable Interest Entities and Unconsolidated Investments in Power Plants | 9 Months Ended |
Sep. 30, 2016 | |
Variable Interest Entities and Unconsolidated Investments [Abstract] | |
Variable interest entities and unconsolidated investments in power plants | Variable Interest Entities and Unconsolidated Investments We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the nine months ended September 30, 2016 . See Note 5 in our 2015 Form 10-K for further information regarding our VIEs. VIE Disclosures Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 10,266 MW at September 30, 2016 and December 31, 2015 , respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of $1 million during each of the three and nine months ended September 30, 2016 and $2 million during each of the three and nine months ended September 30, 2015 . Unconsolidated VIEs and Investments in Power Plants We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby. We account for these entities under the equity method of accounting and include our net equity interest in investments in power plants on our Consolidated Condensed Balance Sheets. At September 30, 2016 and December 31, 2015 , our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions): Ownership Interest as of September 30, 2016 September 30, 2016 December 31, 2015 Greenfield LP 50% $ 70 $ 65 Whitby 50% 10 14 Total investments in power plants $ 80 $ 79 Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At September 30, 2016 and December 31, 2015 , equity method investee debt was approximately $270 million and $ 269 million , respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $135 million and $ 135 million at September 30, 2016 and December 31, 2015 , respectively. Our equity interest in the net income from Greenfield LP and Whitby for the three and nine months ended September 30, 2016 and 2015 , is recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Greenfield LP $ (3 ) $ (3 ) $ (8 ) $ (9 ) Whitby (3 ) (3 ) (8 ) (9 ) Total $ (6 ) $ (6 ) $ (16 ) $ (18 ) Distributions from Greenfield LP were $1 million and $6 million during the three and nine months ended September 30, 2016 , respectively, and $10 million during each of the three and nine months ended September 30, 2015 . Distributions from Whitby were nil and $13 million during each of the three and nine months ended September 30, 2016 and 2015 . |
Debt
Debt | 9 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
Debt | Debt We retrospectively adopted Accounting Standards Update 2015-03 in the first quarter of 2016. As a result, we recast our Consolidated Condensed Balance Sheet at December 31, 2015 resulting in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion. Our debt at September 30, 2016 and December 31, 2015 , was as follows (in millions): September 30, 2016 December 31, 2015 Senior Unsecured Notes $ 3,410 $ 3,406 First Lien Term Loans 2,637 3,277 First Lien Notes 2,408 1,789 Project financing, notes payable and other 1,628 1,715 CCFC Term Loans 1,556 1,565 Capital lease obligations 181 185 Subtotal 11,820 11,937 Less: Current maturities 197 221 Total long-term debt $ 11,623 $ 11,716 Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, decreased to 5.5% for the nine months ended September 30, 2016 , from 5.7% for the same period in 2015. The issuance of our New 2023 First Lien Term Loan in May 2016, our 2024 Senior Unsecured Notes in February 2015 and our 2022 First Lien Term Loan in May 2015 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Term Loans and First Lien Notes with debt carrying lower interest rates. Senior Unsecured Notes The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions): September 30, 2016 December 31, 2015 2023 Senior Unsecured Notes $ 1,236 $ 1,235 2024 Senior Unsecured Notes 642 641 2025 Senior Unsecured Notes 1,532 1,530 Total Senior Unsecured Notes $ 3,410 $ 3,406 First Lien Term Loans The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions): September 30, 2016 December 31, 2015 2019 First Lien Term Loan $ — $ 795 2020 First Lien Term Loan — 378 2022 First Lien Term Loan 1,562 1,571 2023 First Lien Term Loan 530 533 New 2023 First Lien Term Loan 545 — Total First Lien Term Loans $ 2,637 $ 3,277 On May 31, 2016, we entered into a $562 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the New 2023 First Lien Term Loan credit agreement), plus an applicable margin of 2.00% , or (ii) LIBOR plus 3.00% per annum (with no LIBOR floor) and matures on May 31, 2023. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the New 2023 First Lien Term Loan, which is structured as original issue discount and recorded approximately $11 million in deferred financing costs during the second quarter of 2016 related to the issuance of our New 2023 First Lien Term Loan. The New 2023 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and the First Lien Notes. We used the proceeds from the New 2023 First Lien Term Loan and the 2026 First Lien Notes, discussed below, to repay the 2019 and 2020 First Lien Term Loans and recorded $15 million in debt extinguishment costs during the second quarter of 2016 associated with the repayment. First Lien Notes The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions): September 30, 2016 December 31, 2015 2022 First Lien Notes $ 739 $ 737 2023 First Lien Notes 569 568 2024 First Lien Notes 484 484 2026 First Lien Notes 616 — Total First Lien Notes $ 2,408 $ 1,789 On May 31, 2016, we issued $625 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Our 2026 First Lien Notes bear interest at 5.25% payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2016. Our 2026 First Lien Notes mature on June 1, 2026 and contain substantially similar covenants, qualifications, exceptions and limitations as our First Lien Notes. We recorded approximately $9 million in deferred financing costs during the second quarter of 2016 related to the issuance of our 2026 First Lien Notes. Corporate Revolving Facility and Other Letter of Credit Facilities The table below represents amounts issued under our letter of credit facilities at September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 December 31, 2015 Corporate Revolving Facility (1) $ 268 $ 316 CDHI 261 241 Various project financing facilities 232 198 Total $ 761 $ 755 ____________ (1) The Corporate Revolving Facility represents our primary revolving facility. On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020. Fair Value of Debt We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 December 31, 2015 Fair Value Carrying Value Fair Value Carrying Value Senior Unsecured Notes $ 3,429 $ 3,410 $ 3,063 $ 3,406 First Lien Term Loans 2,694 2,637 3,197 3,277 First Lien Notes 2,537 2,408 1,885 1,789 Project financing, notes payable and other (1) 1,576 1,537 1,653 1,608 CCFC Term Loans 1,566 1,556 1,494 1,565 Total $ 11,802 $ 11,548 $ 11,292 $ 11,645 ____________ (1) Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP. We measure the fair value of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy. |
Assets and Liabilities with Rec
Assets and Liabilities with Recurring Fair Value Measurements | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract] | |
Assets and Liabilities with Recurring Fair Value Measurements | Assets and Liabilities with Recurring Fair Value Measurements Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Our cash equivalents are classified within level 1 of the fair value hierarchy. Margin Deposits and Margin Deposits Posted with Us by Our Counterparties — Margin deposits and margin deposits posted with us by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits posted with us by our counterparties are generally cash and cash equivalents and are classified within level 1 of the fair value hierarchy. Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future. We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs. The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate. Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange. Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. OTC options are valued using industry-standard models, including the Black-Scholes option-pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs. For a definition of the different levels in the fair value hierarchy, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies — Fair Value Measurements” in our 2015 Form 10-K. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 , by level within the fair value hierarchy: Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2016 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 786 $ — $ — $ 786 Margin deposits 120 — — 120 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,036 — — 1,036 Commodity forward contracts (2) — 178 60 238 Interest rate hedging instruments — 8 — 8 Total assets $ 1,942 $ 186 $ 60 $ 2,188 Liabilities: Margin deposits posted with us by our counterparties $ 30 $ — $ — $ 30 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,004 — — 1,004 Commodity forward contracts (2) — 310 32 342 Interest rate hedging instruments — 81 — 81 Total liabilities $ 1,034 $ 391 $ 32 $ 1,457 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2015 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 1,134 $ — $ — $ 1,134 Margin deposits 89 — — 89 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,736 — — 1,736 Commodity forward contracts (2) — 220 54 274 Interest rate hedging instruments — 1 — 1 Total assets $ 2,959 $ 221 $ 54 $ 3,234 Liabilities: Margin deposits posted with us by our counterparties $ 35 $ — $ — $ 35 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,604 — — 1,604 Commodity forward contracts (2) — 413 100 513 Interest rate hedging instruments — 90 — 90 Total liabilities $ 1,639 $ 503 $ 100 $ 2,242 ___________ (1) As of September 30, 2016 and December 31, 2015 , we had cash equivalents of $561 million and $906 million included in cash and cash equivalents and $225 million and $228 million included in restricted cash, respectively. (2) Includes OTC swaps and options. At September 30, 2016 and December 31, 2015 , the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at September 30, 2016 and December 31, 2015 : Quantitative Information about Level 3 Fair Value Measurements September 30, 2016 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 7 Discounted cash flow Market price (per MWh) $9.62 — $80.18/MWh Power Congestion Products $ 12 Discounted cash flow Market price (per MWh) $(11.47) — $10.89/MWh December 31, 2015 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ (54 ) Discounted cash flow Market price (per MWh) $6.72 — $83.25/MWh Power Congestion Products $ 8 Discounted cash flow Market price (per MWh) $(11.47) — $12.19/MWh The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Balance, beginning of period $ (63 ) $ 243 $ (46 ) $ 85 Realized and mark-to-market gains (losses): Included in net income: Included in operating revenues (1) 30 70 9 236 Included in fuel and purchased energy expense (2) (31 ) (2 ) (24 ) (2 ) Purchases and settlements: Purchases 1 — 4 3 Settlements 15 (8 ) (4 ) (24 ) Transfers in and/or out of level 3 (3) : Transfers into level 3 (4) 1 — — — Transfers out of level 3 (5) 75 (11 ) 89 (6 ) Balance, end of period $ 28 $ 292 $ 28 $ 292 Change in unrealized gains (losses) relating to instruments still held at end of period $ (1 ) $ 68 $ (15 ) $ 234 ___________ (1) For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations. (2) For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations. (3) We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three and nine months ended September 30, 2016 and 2015 . (4) We had $1 million and nil in gains transferred out of level 2 into level 3 for the three months ended September 30, 2016 and 2015 , respectively. There were no transfers out of level 2 into level 3 for each of the nine months ended September 30, 2016 and 2015 . (5) We had $(75) million in losses and $11 million in gains transferred out of level 3 into level 2 for the three months ended September 30, 2016 and 2015 , respectively, and $(89) million in losses and $6 million in gains transferred out of level 3 into level 2 for the nine months ended September 30, 2016 and 2015 , respectively, due to changes in market liquidity in various power markets. |
Derivative Instruments
Derivative Instruments | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Derivative Instruments Types of Derivative Instruments and Volumetric Information Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels. We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading gains and losses were not material for each of the three and nine months ended September 30, 2016 and 2015 . Interest Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of September 30, 2016 , the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 7 years. As of September 30, 2016 and December 31, 2015 , the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions): Derivative Instruments Notional Amounts September 30, 2016 December 31, 2015 Power (MWh) (49 ) (41 ) Natural gas (MMBtu) 846 996 Environmental credits (Tonnes) 17 8 Interest rate hedging instruments $ 3,791 (1) $ 1,320 ___________ (1) We entered into interest rate hedging instruments during the second quarter of 2016 to hedge approximately $2.5 billion of variable rate corporate debt for 2017 through 2019 which effectively places a ceiling on LIBOR at rates varying from 1.44% to 1.8125% for hedged interest payments. See Note 4 for a further discussion of our First Lien Term Loans. Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. Currently, we do not believe that it is probable that any additional collateral posted as a result of a one credit notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of September 30, 2016 , was $4 million for which we have posted collateral of $1 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $4 million would be required and that no counterparty could request immediate, full settlement. Accounting for Derivative Instruments We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities. Cash Flow Hedges — We only apply hedge accounting to our interest rate hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring. Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas, power, environmental product and fuel oil contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense. Derivatives Included on Our Consolidated Condensed Balance Sheets The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 Commodity Instruments Interest Rate Hedging Instruments Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 959 $ — $ 959 Long-term derivative assets 315 8 323 Total derivative assets $ 1,274 $ 8 $ 1,282 Current derivative liabilities $ 958 $ 33 $ 991 Long-term derivative liabilities 388 48 436 Total derivative liabilities $ 1,346 $ 81 $ 1,427 Net derivative assets (liabilities) $ (72 ) $ (73 ) $ (145 ) December 31, 2015 Commodity Interest Rate Hedging Instruments Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 1,698 $ — $ 1,698 Long-term derivative assets 312 1 313 Total derivative assets $ 2,010 $ 1 $ 2,011 Current derivative liabilities $ 1,697 $ 37 $ 1,734 Long-term derivative liabilities 420 53 473 Total derivative liabilities $ 2,117 $ 90 $ 2,207 Net derivative assets (liabilities) $ (107 ) $ (89 ) $ (196 ) September 30, 2016 December 31, 2015 Fair Value of Derivative Assets Fair Value of Derivative Liabilities Fair Value of Derivative Assets Fair Value of Derivative Liabilities Derivatives designated as cash flow hedging instruments: Interest rate hedging instruments $ 8 $ 81 $ 1 $ 90 Total derivatives designated as cash flow hedging instruments $ 8 $ 81 $ 1 $ 90 Derivatives not designated as hedging instruments: Commodity instruments $ 1,274 $ 1,346 $ 2,010 $ 2,117 Total derivatives not designated as hedging instruments $ 1,274 $ 1,346 $ 2,010 $ 2,117 Total derivatives $ 1,282 $ 1,427 $ 2,011 $ 2,207 We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets Gross Amounts Presented on our Consolidated Condensed Balance Sheets Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets Margin/Cash (Received) Posted (1) Net Amount Derivative assets: Commodity exchange traded futures and swaps contracts $ 1,036 $ (988 ) $ (48 ) $ — Commodity forward contracts 238 (128 ) (17 ) 93 Interest rate hedging instruments 8 — — 8 Total derivative assets $ 1,282 $ (1,116 ) $ (65 ) $ 101 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,004 ) $ 988 $ 16 $ — Commodity forward contracts (342 ) 128 — (214 ) Interest rate hedging instruments (81 ) — — (81 ) Total derivative (liabilities) $ (1,427 ) $ 1,116 $ 16 $ (295 ) Net derivative assets (liabilities) $ (145 ) $ — $ (49 ) $ (194 ) December 31, 2015 Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets Gross Amounts Presented on our Consolidated Condensed Balance Sheets Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets Margin/Cash (Received) Posted (1) Net Amount Derivative assets: Commodity exchange traded futures and swaps contracts $ 1,736 $ (1,602 ) $ (134 ) $ — Commodity forward contracts 274 (202 ) (3 ) 69 Interest rate hedging instruments 1 — — 1 Total derivative assets $ 2,011 $ (1,804 ) $ (137 ) $ 70 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,604 ) $ 1,602 $ 2 $ — Commodity forward contracts (513 ) 202 3 (308 ) Interest rate hedging instruments (90 ) — — (90 ) Total derivative (liabilities) $ (2,207 ) $ 1,804 $ 5 $ (398 ) Net derivative assets (liabilities) $ (196 ) $ — $ (132 ) $ (328 ) ____________ (1) Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral. Derivatives Included on Our Consolidated Condensed Statements of Operations Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our earnings. The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Realized gain (loss) (1)(2) Commodity derivative instruments $ 32 $ 160 $ 213 $ 323 Total realized gain (loss) $ 32 $ 160 $ 213 $ 323 Mark-to-market gain (loss) (3) Commodity derivative instruments $ 109 $ (75 ) $ (22 ) $ (6 ) Interest rate hedging instruments — 1 1 2 Total mark-to-market gain (loss) $ 109 $ (74 ) $ (21 ) $ (4 ) Total activity, net $ 141 $ 86 $ 192 $ 319 ___________ (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. (2) Includes amortization of acquisition date fair value of derivative activity related to the acquisition of Champion Energy. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Realized and mark-to-market gain (loss) Derivatives contracts included in operating revenues (1)(2) $ 308 $ 189 $ 240 $ 423 Derivatives contracts included in fuel and purchased energy expense (1)(2) (167 ) (104 ) (49 ) (106 ) Interest rate hedging instruments included in interest expense (3) — 1 1 2 Total activity, net $ 141 $ 86 $ 192 $ 319 ___________ (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. (2) Includes amortization of acquisition date fair value of derivative activity related to the acquisition of Champion Energy. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. Derivatives Included in OCI and AOCI The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions): Three Months Ended September 30, Three Months Ended September 30, Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3)(4) 2016 2015 2016 2015 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate hedging instruments (1)(2) $ 18 $ (4 ) $ (11 ) $ (12 ) Interest expense Nine Months Ended September 30, Nine Months Ended September 30, Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3)(4) 2016 2015 2016 2015 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate hedging instruments (1)(2) $ — $ 4 $ (33 ) $ (36 ) Interest expense ____________ (1) We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and nine months ended September 30, 2016 and 2015 . (2) We recorded an income tax expense of nil for each of the three and nine months ended September 30, 2016 and 2015 , in AOCI related to our cash flow hedging activities. (3) Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $127 million and $127 million at September 30, 2016 and December 31, 2015 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $11 million and $11 million at September 30, 2016 and December 31, 2015 , respectively. (4) Includes a loss of $1 million for each of the three and nine months ended September 30, 2016 , that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur. We estimate that pre-tax net losses of $39 million would be reclassified from AOCI into interest expense during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months. |
Use of Collateral
Use of Collateral | 9 Months Ended |
Sep. 30, 2016 | |
Use of Collateral [Abstract] | |
Use of Collateral [Text Block] | Use of Collateral We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate hedging instruments in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements. The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 December 31, 2015 Margin deposits (1) $ 120 $ 89 Natural gas and power prepayments 27 34 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 147 $ 123 Letters of credit issued $ 586 $ 600 First priority liens under power and natural gas agreements (3) 299 382 First priority liens under interest rate hedging instruments 83 92 Total letters of credit and first priority liens with our counterparties $ 968 $ 1,074 Margin deposits posted with us by our counterparties (1)(4) $ 30 $ 35 Letters of credit posted with us by our counterparties 35 24 Total margin deposits and letters of credit posted with us by our counterparties $ 65 $ 59 ___________ (1) Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements. (2) At September 30, 2016 and December 31, 2015 , $138 million and $101 million , respectively, were included in margin deposits and other prepaid expense and $9 million and $22 million , respectively, were included in other assets on our Consolidated Condensed Balance Sheets. (3) Includes $268 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at September 30, 2016 and December 31, 2015 , respectively. (4) Included in other current liabilities on our Consolidated Condensed Balance Sheets. Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Income Tax Expense (Benefit) The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Income tax expense (benefit) $ (4 ) $ 28 $ 17 $ 32 Effective tax rate (1 )% 9 % 20 % 10 % Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the effect of our NOLs, changes in unrecognized tax benefits and valuation allowances. For the three and nine months ended September 30, 2016 and 2015 , our income tax expense (benefit) is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs or valuation allowances. See Note 10 in our 2015 Form 10-K for further information regarding our NOLs. Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs occurred. Any adjustment of state or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies. Unrecognized Tax Benefits — At September 30, 2016 , we had unrecognized tax benefits of $ 58 million . If recognized, $ 18 million of our unrecognized tax benefits could affect the annual effective tax rate and $ 40 million , related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no effect on our effective tax rate. We had accrued interest and penalties of $ 13 million for income tax matters at September 30, 2016 . We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of nil and $19 million in unrecognized tax benefits could occur within the next twelve months. |
Earnings (Loss) per Share
Earnings (Loss) per Share | 9 Months Ended |
Sep. 30, 2016 | |
Earnings Per Share [Abstract] | |
Earnings Per Share [Text Block] | Earnings per Share We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and nine months ended September 30, 2016 and 2015 are as follows (shares in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Diluted weighted average shares calculation: Weighted average shares outstanding (basic) 354,215 355,443 353,929 365,053 Share-based awards 2,137 2,233 2,051 3,166 Weighted average shares outstanding (diluted) 356,352 357,676 355,980 368,219 We excluded the following items from diluted earnings per common share for the three and nine months ended September 30, 2016 and 2015 , because they were anti-dilutive (shares in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Share-based awards 1,610 4,982 1,679 4,208 |
Stock-Based Compensation
Stock-Based Compensation | 9 Months Ended |
Sep. 30, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | Stock-Based Compensation Equity Classified Share-Based Awards Stock-based compensation expense recognized for our equity classified share-based awards was $7 million and $ 8 million for the three months ended September 30, 2016 and 2015 , respectively, and $ 22 million and $ 24 million for the nine months ended September 30, 2016 and 2015 , respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the nine months ended September 30, 2016 and 2015 . At September 30, 2016 , there was unrecognized compensation cost of $ 31 million related to restricted stock which is expected to be recognized over a weighted average period of 1.4 years. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans when stock options are exercised and for other share-based awards. A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 2016 , is as follows: Number of Restricted Stock Awards Weighted Average Grant-Date Fair Value Nonvested — December 31, 2015 3,528,270 $ 19.91 Granted 2,947,826 $ 12.40 Forfeited 218,932 $ 16.21 Vested 1,301,920 $ 19.02 Nonvested — September 30, 2016 4,955,244 $ 15.84 The total fair value of our restricted stock and restricted stock units that vested during the nine months ended September 30, 2016 and 2015 was approximately $ 16 million and $ 34 million , respectively. Liability Classified Share-Based Awards During the first quarter of 2016, our Board of Directors approved the award of performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s TSR over the three-year performance period of January 1, 2016 through December 31, 2018 compared with the TSR performance of the S&P 500 companies over the same period, as modified by the IPP Sector Modifier which may either increase or decrease the payout based on Calpine’s TSR within its IPP Peers. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $ (1) million for each of the three months ended September 30, 2016 and 2015 and $ 1 million and $ (5) million for the nine months ended September 30, 2016 and 2015 , respectively. A summary of our performance share unit activity for the nine months ended September 30, 2016 , is as follows: Number of Performance Share Units Weighted Average Grant-Date Fair Value Nonvested — December 31, 2015 517,906 $ 23.36 Granted 657,807 $ 14.81 Vested (1) 3,249 $ 23.91 Nonvested — September 30, 2016 1,172,464 $ 18.56 ___________ (1) In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date. For a further discussion of the Calpine Equity Incentive Plans, see Note 12 in our 2015 Form 10-K. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Litigation We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows. Environmental Matters We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material effect on our financial condition, results of operations or cash flows or that would significantly change our operations. |
Segment Information
Segment Information | 9 Months Ended |
Sep. 30, 2016 | |
Segment Reporting [Abstract] | |
Segment Information | Segment Information We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. At September 30, 2016 , our reportable segments were West (including geothermal), Texas and East (including Canada). We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments. Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions). Three Months Ended September 30, 2016 West Texas East Consolidation and Elimination Total Revenues from external customers $ 524 $ 1,067 $ 764 $ — $ 2,355 Intersegment revenues 1 3 2 (6 ) — Total operating revenues $ 525 $ 1,070 $ 766 $ (6 ) $ 2,355 Commodity Margin $ 298 $ 198 $ 324 $ — $ 820 Add: Mark-to-market commodity activity, net and other (1) 11 110 (51 ) (7 ) 63 Less: Plant operating expense 79 65 78 (7 ) 215 Depreciation and amortization expense 56 53 52 — 161 Sales, general and other administrative expense 9 13 12 (1 ) 33 Other operating expenses 8 2 7 1 18 (Income) from unconsolidated investments in power plants — — (6 ) — (6 ) Income from operations 157 175 130 — 462 Interest expense, net of interest income 157 Other (income) expense, net 8 Income before income taxes $ 297 Three Months Ended September 30, 2015 West Texas East Consolidation and Elimination Total Revenues from external customers $ 736 $ 709 $ 503 $ — $ 1,948 Intersegment revenues 1 4 3 (8 ) — Total operating revenues $ 737 $ 713 $ 506 $ (8 ) $ 1,948 Commodity Margin $ 385 $ 264 $ 325 $ — $ 974 Add: Mark-to-market commodity activity, net and other (1) 68 (98 ) (62 ) (7 ) (99 ) Less: Plant operating expense 87 62 57 (6 ) 200 Depreciation and amortization expense 61 58 48 (1 ) 166 Sales, general and other administrative expense 7 15 10 1 33 Other operating expenses 8 2 8 (2 ) 16 (Income) from unconsolidated investments in power plants — — (6 ) — (6 ) Income from operations 290 29 146 1 466 Interest expense, net of interest income 158 Other (income) expense, net 1 Income before income taxes $ 307 Nine Months Ended September 30, 2016 West Texas East Consolidation and Elimination Total Revenues from external customers $ 1,159 $ 2,129 $ 1,846 $ — $ 5,134 Intersegment revenues 4 10 9 (23 ) — Total operating revenues $ 1,163 $ 2,139 $ 1,855 $ (23 ) $ 5,134 Commodity Margin $ 749 $ 511 $ 797 $ — $ 2,057 Add: Mark-to-market commodity activity, net and other (2) (5 ) 7 (44 ) (21 ) (63 ) Less: Plant operating expense 268 236 258 (21 ) 741 Depreciation and amortization expense 181 159 163 — 503 Sales, general and other administrative expense 27 43 36 — 106 Other operating expenses 23 6 27 (1 ) 55 (Income) from unconsolidated investments in power plants — — (16 ) — (16 ) Income from operations 245 74 285 1 605 Interest expense, net of interest income 469 Debt extinguishment costs and other (income) expense, net 36 Income before income taxes $ 100 Nine Months Ended September 30, 2015 West Texas East Consolidation and Elimination Total Revenues from external customers $ 1,672 $ 1,860 $ 1,504 $ — $ 5,036 Intersegment revenues 3 12 7 (22 ) — Total operating revenues $ 1,675 $ 1,872 $ 1,511 $ (22 ) $ 5,036 Commodity Margin $ 843 $ 583 $ 740 $ — $ 2,166 Add: Mark-to-market commodity activity, net and other (2) 173 (47 ) (84 ) (21 ) 21 Less: Plant operating expense 313 233 206 (20 ) 732 Depreciation and amortization expense 193 157 135 (1 ) 484 Sales, general and other administrative expense 23 47 29 1 100 Other operating expenses 28 6 24 (2 ) 56 (Income) from unconsolidated investments in power plants — — (18 ) — (18 ) Income from operations 459 93 280 1 833 Interest expense, net of interest income 468 Debt modification and extinguishment costs and other (income) expense, net 40 Income before income taxes $ 325 _________ (1) Includes $40 million and $ 41 million of lease levelization and $25 million and $ 4 million of amortization expense for the three months ended September 30, 2016 and 2015 , respectively. (2) Includes $(2) million and $ (1) million of lease levelization and $79 million and $ 11 million of amortization expense for the nine months ended September 30, 2016 and 2015 , respectively. |
Basis of Presentation and Sum19
Basis of Presentation and Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2016 | |
Accounting Policies [Abstract] | |
Basis of interim presentation | Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2015 , included in our 2015 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts. |
Use of estimates in preparation of financial statements | Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates. |
Cash and cash equivalents | Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. |
Restricted cash | Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows. |
Business Interruption Proceeds | Business Interruption Proceeds — We record business interruption insurance proceeds when they are realizable and recorded approximately $9 million and $17 million of business interruption proceeds in operating revenues during the three and nine months ended September 30, 2016 , respectively. We did not record any business interruption proceeds during the three and nine months ended September 30, 2015 . |
Property, Plant and Equipment, Impairment | At September 30, 2016 and December 31, 2015 , the components of property, plant and equipment are stated at cost less accumulated depreciation |
Consolidation, Variable Interest Entity, Policy | We consolidate all of our VIEs where we have determined that we are the primary beneficiary. We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby. We account for these entities under the equity method of accounting and include our net equity interest in investments in power plants on our Consolidated Condensed Balance Sheets. |
Fair Value of Financial Instruments | We measure the fair value of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy. Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Our cash equivalents are classified within level 1 of the fair value hierarchy. Margin Deposits and Margin Deposits Posted with Us by Our Counterparties — Margin deposits and margin deposits posted with us by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits posted with us by our counterparties are generally cash and cash equivalents and are classified within level 1 of the fair value hierarchy. Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future. We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs. The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate. Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange. Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. OTC options are valued using industry-standard models, including the Black-Scholes option-pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs. |
Derivatives | We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities. Cash Flow Hedges — We only apply hedge accounting to our interest rate hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring. Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas, power, environmental product and fuel oil contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense. We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. |
Commitments and contingencies | On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows. |
Impairment or Disposal of Long-Lived Assets, Including Intangible Assets, Policy | We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value. In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material. When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material. We did not record any material impairments during the three and nine months ended September 30, 2016 and 2015 . |
New accounting pronouncements, policy | Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard is effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We are currently assessing the potential effect the revenue recognition standard may have on our financial condition, results of operations or cash flows. Consolidation — In February 2015, the FASB issued Accounting Standards Update 2015-02, “Amendments to the Consolidation Analysis.” The standard amends the consolidation model used in determining whether a reporting entity should consolidate the financial results of certain of its partially- and wholly-owned subsidiaries. All of our subsidiaries are subject to reevaluation under the revised consolidation model. Specifically, the amendments (i) modify the evaluation of whether limited partnerships and similar legal entities are voting interest entities or VIEs, (ii) eliminate the presumption that a general partner should consolidate the financial results of a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and (iv) provide an exception for certain types of entities. This standard became effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period. We adopted Accounting Standards Update 2015-02 in the first quarter of 2016 which did not have a material effect on our financial condition, results of operations or cash flows. Debt Issuance Costs — In April 2015, the FASB issued Accounting Standards Update 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” The standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, which is consistent with the presentation of debt discounts. In August 2015, the FASB issued Accounting Standards Update 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” which allows an entity to present debt issuance costs associated with a line-of-credit arrangement as an asset regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The standards became effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We retrospectively adopted Accounting Standard Updates 2015-03 and 2015-15 in the first quarter of 2016 which resulted in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion on our Consolidated Condensed Balance Sheet at December 31, 2015 . Cloud Computing Arrangements — In April 2015, the FASB issued Accounting Standards Update 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” The standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard became effective for fiscal years beginning after December 15, 2015, including interim periods. We adopted Accounting Standards Update 2015-05 in the first quarter of 2016 which did not have a material effect on our financial condition, results of operations or cash flows. Inventory — In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” The standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. We are currently assessing the potential effect this standard may have on our financial condition, results of operations or cash flows. Stock-Based Compensation — In March 2016, the FASB issued Accounting Standards Update 2016-09, “Improvements to Employee Share-Based Payment Accounting.” The standard applies to several aspects of accounting for stock-based compensation including the recognition of excess tax benefits and deficiencies and their related presentation in the statement of cash flows as well as accounting for forfeitures. The standard also requires that shares withheld to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees be presented as a financing activity in the statement of cash flows. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and allows for prospective, retrospective or modified retrospective adoption, depending on the area covered in the standard, with early adoption permitted. We early adopted Accounting Standards Update 2016-09 in the third quarter of 2016. The cumulative-effect adjustment to accumulated deficit for all excess tax benefits not previously recognized as of the beginning of the year is substantially offset by a corresponding change in the valuation allowance. The implementation of Accounting Standards Update 2016-09 did not have a material effect on our financial condition, results of operations or cash flows. Statement of Cash Flows — In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and allows for retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard. |
Basis of Presentation and Sum20
Basis of Presentation and Summary of Significant Accounting Policies (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Accounting Policies [Abstract] | |
Schedule of components of restricted cash | The table below represents the components of our restricted cash as of September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 December 31, 2015 Current Non-Current Total Current Non-Current Total Debt service $ 39 $ 7 $ 46 $ 28 $ 8 $ 36 Construction/major maintenance 34 4 38 50 2 52 Security/project/insurance 134 2 136 136 — 136 Other 3 2 5 2 2 4 Total $ 210 $ 15 $ 225 $ 216 $ 12 $ 228 |
Schedule of property, plant and equipment | Property, Plant and Equipment, Net — At September 30, 2016 and December 31, 2015 , the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions): September 30, 2016 December 31, 2015 Depreciable Lives Buildings, machinery and equipment $ 16,478 $ 16,294 3 – 46 Years Geothermal properties 1,376 1,319 13 – 58 Years Other 228 208 3 – 46 Years 18,082 17,821 Less: Accumulated depreciation 5,719 5,377 12,363 12,444 Land 119 120 Construction in progress 587 448 Property, plant and equipment, net $ 13,069 $ 13,012 |
Acquisition Assets Held for Sal
Acquisition Assets Held for Sale (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Assets held for sale [Abstract] | |
Disclosure of Long Lived Assets Held-for-sale [Table Text Block] | The table below presents the components of our current assets held for sale at September 30, 2016 (in millions): September 30, 2016 Assets: Current assets $ 12 Property, plant and equipment, net 401 Other long-term assets 39 Total current assets held for sale $ 452 |
Variable Interest Entities an22
Variable Interest Entities and Unconsolidated Investments in Power Plants (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Variable Interest Entities and Unconsolidated Investments [Abstract] | |
Schedule of equity method investments | At September 30, 2016 and December 31, 2015 , our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions): Ownership Interest as of September 30, 2016 September 30, 2016 December 31, 2015 Greenfield LP 50% $ 70 $ 65 Whitby 50% 10 14 Total investments in power plants $ 80 $ 79 |
Income (loss) from unconsolidated investments in power plants | The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Greenfield LP $ (3 ) $ (3 ) $ (8 ) $ (9 ) Whitby (3 ) (3 ) (8 ) (9 ) Total $ (6 ) $ (6 ) $ (16 ) $ (18 ) |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Debt Disclosure [Abstract] | |
Schedule of long-term debt instruments | Our debt at September 30, 2016 and December 31, 2015 , was as follows (in millions): September 30, 2016 December 31, 2015 Senior Unsecured Notes $ 3,410 $ 3,406 First Lien Term Loans 2,637 3,277 First Lien Notes 2,408 1,789 Project financing, notes payable and other 1,628 1,715 CCFC Term Loans 1,556 1,565 Capital lease obligations 181 185 Subtotal 11,820 11,937 Less: Current maturities 197 221 Total long-term debt $ 11,623 $ 11,716 |
Senior Unsecured Notes | The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions): September 30, 2016 December 31, 2015 2023 Senior Unsecured Notes $ 1,236 $ 1,235 2024 Senior Unsecured Notes 642 641 2025 Senior Unsecured Notes 1,532 1,530 Total Senior Unsecured Notes $ 3,410 $ 3,406 |
First Lien Term Loans | The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions): September 30, 2016 December 31, 2015 2019 First Lien Term Loan $ — $ 795 2020 First Lien Term Loan — 378 2022 First Lien Term Loan 1,562 1,571 2023 First Lien Term Loan 530 533 New 2023 First Lien Term Loan 545 — Total First Lien Term Loans $ 2,637 $ 3,277 |
First Lien Notes | The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions): September 30, 2016 December 31, 2015 2022 First Lien Notes $ 739 $ 737 2023 First Lien Notes 569 568 2024 First Lien Notes 484 484 2026 First Lien Notes 616 — Total First Lien Notes $ 2,408 $ 1,789 |
Schedule of line of credit facilities | The table below represents amounts issued under our letter of credit facilities at September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 December 31, 2015 Corporate Revolving Facility (1) $ 268 $ 316 CDHI 261 241 Various project financing facilities 232 198 Total $ 761 $ 755 ____________ (1) The Corporate Revolving Facility represents our primary revolving facility. |
Schedule of carrying values and estimated fair values of debt instruments | The following table details the fair values and carrying values of our debt instruments at September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 December 31, 2015 Fair Value Carrying Value Fair Value Carrying Value Senior Unsecured Notes $ 3,429 $ 3,410 $ 3,063 $ 3,406 First Lien Term Loans 2,694 2,637 3,197 3,277 First Lien Notes 2,537 2,408 1,885 1,789 Project financing, notes payable and other (1) 1,576 1,537 1,653 1,608 CCFC Term Loans 1,566 1,556 1,494 1,565 Total $ 11,802 $ 11,548 $ 11,292 $ 11,645 ____________ (1) Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP. |
Assets and Liabilities with R24
Assets and Liabilities with Recurring Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract] | |
Fair Value, Measurement Inputs, Disclosure | The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 , by level within the fair value hierarchy: Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2016 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 786 $ — $ — $ 786 Margin deposits 120 — — 120 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,036 — — 1,036 Commodity forward contracts (2) — 178 60 238 Interest rate hedging instruments — 8 — 8 Total assets $ 1,942 $ 186 $ 60 $ 2,188 Liabilities: Margin deposits posted with us by our counterparties $ 30 $ — $ — $ 30 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,004 — — 1,004 Commodity forward contracts (2) — 310 32 342 Interest rate hedging instruments — 81 — 81 Total liabilities $ 1,034 $ 391 $ 32 $ 1,457 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2015 Level 1 Level 2 Level 3 Total (in millions) Assets: Cash equivalents (1) $ 1,134 $ — $ — $ 1,134 Margin deposits 89 — — 89 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,736 — — 1,736 Commodity forward contracts (2) — 220 54 274 Interest rate hedging instruments — 1 — 1 Total assets $ 2,959 $ 221 $ 54 $ 3,234 Liabilities: Margin deposits posted with us by our counterparties $ 35 $ — $ — $ 35 Commodity instruments: Commodity exchange traded futures and swaps contracts 1,604 — — 1,604 Commodity forward contracts (2) — 413 100 513 Interest rate hedging instruments — 90 — 90 Total liabilities $ 1,639 $ 503 $ 100 $ 2,242 ___________ (1) As of September 30, 2016 and December 31, 2015 , we had cash equivalents of $561 million and $906 million included in cash and cash equivalents and $225 million and $228 million included in restricted cash, respectively. (2) Includes OTC swaps and options. |
Fair Value Inputs, Assets, Quantitative Information | The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at September 30, 2016 and December 31, 2015 : Quantitative Information about Level 3 Fair Value Measurements September 30, 2016 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ 7 Discounted cash flow Market price (per MWh) $9.62 — $80.18/MWh Power Congestion Products $ 12 Discounted cash flow Market price (per MWh) $(11.47) — $10.89/MWh December 31, 2015 Fair Value, Net Asset Significant Unobservable (Liability) Valuation Technique Input Range (in millions) Power Contracts $ (54 ) Discounted cash flow Market price (per MWh) $6.72 — $83.25/MWh Power Congestion Products $ 8 Discounted cash flow Market price (per MWh) $(11.47) — $12.19/MWh |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block] | The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Balance, beginning of period $ (63 ) $ 243 $ (46 ) $ 85 Realized and mark-to-market gains (losses): Included in net income: Included in operating revenues (1) 30 70 9 236 Included in fuel and purchased energy expense (2) (31 ) (2 ) (24 ) (2 ) Purchases and settlements: Purchases 1 — 4 3 Settlements 15 (8 ) (4 ) (24 ) Transfers in and/or out of level 3 (3) : Transfers into level 3 (4) 1 — — — Transfers out of level 3 (5) 75 (11 ) 89 (6 ) Balance, end of period $ 28 $ 292 $ 28 $ 292 Change in unrealized gains (losses) relating to instruments still held at end of period $ (1 ) $ 68 $ (15 ) $ 234 ___________ (1) For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations. (2) For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations. (3) We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three and nine months ended September 30, 2016 and 2015 . (4) We had $1 million and nil in gains transferred out of level 2 into level 3 for the three months ended September 30, 2016 and 2015 , respectively. There were no transfers out of level 2 into level 3 for each of the nine months ended September 30, 2016 and 2015 . (5) We had $(75) million in losses and $11 million in gains transferred out of level 3 into level 2 for the three months ended September 30, 2016 and 2015 , respectively, and $(89) million in losses and $6 million in gains transferred out of level 3 into level 2 for the nine months ended September 30, 2016 and 2015 , respectively, due to changes in market liquidity in various power markets. |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | As of September 30, 2016 and December 31, 2015 , the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions): Derivative Instruments Notional Amounts September 30, 2016 December 31, 2015 Power (MWh) (49 ) (41 ) Natural gas (MMBtu) 846 996 Environmental credits (Tonnes) 17 8 Interest rate hedging instruments $ 3,791 (1) $ 1,320 ___________ (1) We entered into interest rate hedging instruments during the second quarter of 2016 to hedge approximately $2.5 billion of variable rate corporate debt for 2017 through 2019 which effectively places a ceiling on LIBOR at rates varying from 1.44% to 1.8125% for hedged interest payments. See Note 4 for a further discussion of our First Lien Term Loans. |
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location [Table Text Block] | The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 Commodity Instruments Interest Rate Hedging Instruments Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 959 $ — $ 959 Long-term derivative assets 315 8 323 Total derivative assets $ 1,274 $ 8 $ 1,282 Current derivative liabilities $ 958 $ 33 $ 991 Long-term derivative liabilities 388 48 436 Total derivative liabilities $ 1,346 $ 81 $ 1,427 Net derivative assets (liabilities) $ (72 ) $ (73 ) $ (145 ) December 31, 2015 Commodity Interest Rate Hedging Instruments Total Derivative Instruments Balance Sheet Presentation Current derivative assets $ 1,698 $ — $ 1,698 Long-term derivative assets 312 1 313 Total derivative assets $ 2,010 $ 1 $ 2,011 Current derivative liabilities $ 1,697 $ 37 $ 1,734 Long-term derivative liabilities 420 53 473 Total derivative liabilities $ 2,117 $ 90 $ 2,207 Net derivative assets (liabilities) $ (107 ) $ (89 ) $ (196 ) |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | September 30, 2016 December 31, 2015 Fair Value of Derivative Assets Fair Value of Derivative Liabilities Fair Value of Derivative Assets Fair Value of Derivative Liabilities Derivatives designated as cash flow hedging instruments: Interest rate hedging instruments $ 8 $ 81 $ 1 $ 90 Total derivatives designated as cash flow hedging instruments $ 8 $ 81 $ 1 $ 90 Derivatives not designated as hedging instruments: Commodity instruments $ 1,274 $ 1,346 $ 2,010 $ 2,117 Total derivatives not designated as hedging instruments $ 1,274 $ 1,346 $ 2,010 $ 2,117 Total derivatives $ 1,282 $ 1,427 $ 2,011 $ 2,207 |
Derivative Instruments Subject to Master Netting Arrangements [Table Text Block] | The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets Gross Amounts Presented on our Consolidated Condensed Balance Sheets Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets Margin/Cash (Received) Posted (1) Net Amount Derivative assets: Commodity exchange traded futures and swaps contracts $ 1,036 $ (988 ) $ (48 ) $ — Commodity forward contracts 238 (128 ) (17 ) 93 Interest rate hedging instruments 8 — — 8 Total derivative assets $ 1,282 $ (1,116 ) $ (65 ) $ 101 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,004 ) $ 988 $ 16 $ — Commodity forward contracts (342 ) 128 — (214 ) Interest rate hedging instruments (81 ) — — (81 ) Total derivative (liabilities) $ (1,427 ) $ 1,116 $ 16 $ (295 ) Net derivative assets (liabilities) $ (145 ) $ — $ (49 ) $ (194 ) December 31, 2015 Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets Gross Amounts Presented on our Consolidated Condensed Balance Sheets Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets Margin/Cash (Received) Posted (1) Net Amount Derivative assets: Commodity exchange traded futures and swaps contracts $ 1,736 $ (1,602 ) $ (134 ) $ — Commodity forward contracts 274 (202 ) (3 ) 69 Interest rate hedging instruments 1 — — 1 Total derivative assets $ 2,011 $ (1,804 ) $ (137 ) $ 70 Derivative (liabilities): Commodity exchange traded futures and swaps contracts $ (1,604 ) $ 1,602 $ 2 $ — Commodity forward contracts (513 ) 202 3 (308 ) Interest rate hedging instruments (90 ) — — (90 ) Total derivative (liabilities) $ (2,207 ) $ 1,804 $ 5 $ (398 ) Net derivative assets (liabilities) $ (196 ) $ — $ (132 ) $ (328 ) ____________ (1) Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral. |
Realized Unrealized Gain Loss by Instrument | The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Realized gain (loss) (1)(2) Commodity derivative instruments $ 32 $ 160 $ 213 $ 323 Total realized gain (loss) $ 32 $ 160 $ 213 $ 323 Mark-to-market gain (loss) (3) Commodity derivative instruments $ 109 $ (75 ) $ (22 ) $ (6 ) Interest rate hedging instruments — 1 1 2 Total mark-to-market gain (loss) $ 109 $ (74 ) $ (21 ) $ (4 ) Total activity, net $ 141 $ 86 $ 192 $ 319 ___________ (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. (2) Includes amortization of acquisition date fair value of derivative activity related to the acquisition of Champion Energy. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. |
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location | Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Realized and mark-to-market gain (loss) Derivatives contracts included in operating revenues (1)(2) $ 308 $ 189 $ 240 $ 423 Derivatives contracts included in fuel and purchased energy expense (1)(2) (167 ) (104 ) (49 ) (106 ) Interest rate hedging instruments included in interest expense (3) — 1 1 2 Total activity, net $ 141 $ 86 $ 192 $ 319 ___________ (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. (2) Includes amortization of acquisition date fair value of derivative activity related to the acquisition of Champion Energy. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. |
Derivatives Designated as Hedges | The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions): Three Months Ended September 30, Three Months Ended September 30, Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3)(4) 2016 2015 2016 2015 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate hedging instruments (1)(2) $ 18 $ (4 ) $ (11 ) $ (12 ) Interest expense Nine Months Ended September 30, Nine Months Ended September 30, Gain (Loss) Recognized in OCI (Effective Portion) Gain (Loss) Reclassified from AOCI into Income (Effective Portion) (3)(4) 2016 2015 2016 2015 Affected Line Item on the Consolidated Condensed Statements of Operations Interest rate hedging instruments (1)(2) $ — $ 4 $ (33 ) $ (36 ) Interest expense ____________ (1) We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and nine months ended September 30, 2016 and 2015 . (2) We recorded an income tax expense of nil for each of the three and nine months ended September 30, 2016 and 2015 , in AOCI related to our cash flow hedging activities. (3) Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $127 million and $127 million at September 30, 2016 and December 31, 2015 , respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $11 million and $11 million at September 30, 2016 and December 31, 2015 , respectively. (4) Includes a loss of $1 million for each of the three and nine months ended September 30, 2016 , that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur. |
Use of Collateral (Tables)
Use of Collateral (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Use of Collateral [Abstract] | |
Schedule of Collateral | The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of September 30, 2016 and December 31, 2015 (in millions): September 30, 2016 December 31, 2015 Margin deposits (1) $ 120 $ 89 Natural gas and power prepayments 27 34 Total margin deposits and natural gas and power prepayments with our counterparties (2) $ 147 $ 123 Letters of credit issued $ 586 $ 600 First priority liens under power and natural gas agreements (3) 299 382 First priority liens under interest rate hedging instruments 83 92 Total letters of credit and first priority liens with our counterparties $ 968 $ 1,074 Margin deposits posted with us by our counterparties (1)(4) $ 30 $ 35 Letters of credit posted with us by our counterparties 35 24 Total margin deposits and letters of credit posted with us by our counterparties $ 65 $ 59 ___________ (1) Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements. (2) At September 30, 2016 and December 31, 2015 , $138 million and $101 million , respectively, were included in margin deposits and other prepaid expense and $9 million and $22 million , respectively, were included in other assets on our Consolidated Condensed Balance Sheets. (3) Includes $268 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at September 30, 2016 and December 31, 2015 , respectively. (4) Included in other current liabilities on our Consolidated Condensed Balance Sheets. |
Income Taxes Income Taxes (Tabl
Income Taxes Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Income tax expense (benefit) $ (4 ) $ 28 $ 17 $ 32 Effective tax rate (1 )% 9 % 20 % 10 % |
Earnings (Loss) per Share (Tabl
Earnings (Loss) per Share (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Earnings Per Share [Abstract] | |
Schedule of Weighted Average Number of Shares [Table Text Block] | Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and nine months ended September 30, 2016 and 2015 are as follows (shares in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Diluted weighted average shares calculation: Weighted average shares outstanding (basic) 354,215 355,443 353,929 365,053 Share-based awards 2,137 2,233 2,051 3,166 Weighted average shares outstanding (diluted) 356,352 357,676 355,980 368,219 |
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share | We excluded the following items from diluted earnings per common share for the three and nine months ended September 30, 2016 and 2015 , because they were anti-dilutive (shares in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2016 2015 2016 2015 Share-based awards 1,610 4,982 1,679 4,208 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block] | A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 2016 , is as follows: Number of Restricted Stock Awards Weighted Average Grant-Date Fair Value Nonvested — December 31, 2015 3,528,270 $ 19.91 Granted 2,947,826 $ 12.40 Forfeited 218,932 $ 16.21 Vested 1,301,920 $ 19.02 Nonvested — September 30, 2016 4,955,244 $ 15.84 |
Schedule of Share-based Compensation, Activity | A summary of our performance share unit activity for the nine months ended September 30, 2016 , is as follows: Number of Performance Share Units Weighted Average Grant-Date Fair Value Nonvested — December 31, 2015 517,906 $ 23.36 Granted 657,807 $ 14.81 Vested (1) 3,249 $ 23.91 Nonvested — September 30, 2016 1,172,464 $ 18.56 ___________ (1) In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date. |
Segment Information (Tables)
Segment Information (Tables) | 9 Months Ended |
Sep. 30, 2016 | |
Segment Reporting [Abstract] | |
Schedule of Financial Data for Segments | The tables below show our financial data for our segments for the periods indicated (in millions). Three Months Ended September 30, 2016 West Texas East Consolidation and Elimination Total Revenues from external customers $ 524 $ 1,067 $ 764 $ — $ 2,355 Intersegment revenues 1 3 2 (6 ) — Total operating revenues $ 525 $ 1,070 $ 766 $ (6 ) $ 2,355 Commodity Margin $ 298 $ 198 $ 324 $ — $ 820 Add: Mark-to-market commodity activity, net and other (1) 11 110 (51 ) (7 ) 63 Less: Plant operating expense 79 65 78 (7 ) 215 Depreciation and amortization expense 56 53 52 — 161 Sales, general and other administrative expense 9 13 12 (1 ) 33 Other operating expenses 8 2 7 1 18 (Income) from unconsolidated investments in power plants — — (6 ) — (6 ) Income from operations 157 175 130 — 462 Interest expense, net of interest income 157 Other (income) expense, net 8 Income before income taxes $ 297 Three Months Ended September 30, 2015 West Texas East Consolidation and Elimination Total Revenues from external customers $ 736 $ 709 $ 503 $ — $ 1,948 Intersegment revenues 1 4 3 (8 ) — Total operating revenues $ 737 $ 713 $ 506 $ (8 ) $ 1,948 Commodity Margin $ 385 $ 264 $ 325 $ — $ 974 Add: Mark-to-market commodity activity, net and other (1) 68 (98 ) (62 ) (7 ) (99 ) Less: Plant operating expense 87 62 57 (6 ) 200 Depreciation and amortization expense 61 58 48 (1 ) 166 Sales, general and other administrative expense 7 15 10 1 33 Other operating expenses 8 2 8 (2 ) 16 (Income) from unconsolidated investments in power plants — — (6 ) — (6 ) Income from operations 290 29 146 1 466 Interest expense, net of interest income 158 Other (income) expense, net 1 Income before income taxes $ 307 Nine Months Ended September 30, 2016 West Texas East Consolidation and Elimination Total Revenues from external customers $ 1,159 $ 2,129 $ 1,846 $ — $ 5,134 Intersegment revenues 4 10 9 (23 ) — Total operating revenues $ 1,163 $ 2,139 $ 1,855 $ (23 ) $ 5,134 Commodity Margin $ 749 $ 511 $ 797 $ — $ 2,057 Add: Mark-to-market commodity activity, net and other (2) (5 ) 7 (44 ) (21 ) (63 ) Less: Plant operating expense 268 236 258 (21 ) 741 Depreciation and amortization expense 181 159 163 — 503 Sales, general and other administrative expense 27 43 36 — 106 Other operating expenses 23 6 27 (1 ) 55 (Income) from unconsolidated investments in power plants — — (16 ) — (16 ) Income from operations 245 74 285 1 605 Interest expense, net of interest income 469 Debt extinguishment costs and other (income) expense, net 36 Income before income taxes $ 100 Nine Months Ended September 30, 2015 West Texas East Consolidation and Elimination Total Revenues from external customers $ 1,672 $ 1,860 $ 1,504 $ — $ 5,036 Intersegment revenues 3 12 7 (22 ) — Total operating revenues $ 1,675 $ 1,872 $ 1,511 $ (22 ) $ 5,036 Commodity Margin $ 843 $ 583 $ 740 $ — $ 2,166 Add: Mark-to-market commodity activity, net and other (2) 173 (47 ) (84 ) (21 ) 21 Less: Plant operating expense 313 233 206 (20 ) 732 Depreciation and amortization expense 193 157 135 (1 ) 484 Sales, general and other administrative expense 23 47 29 1 100 Other operating expenses 28 6 24 (2 ) 56 (Income) from unconsolidated investments in power plants — — (18 ) — (18 ) Income from operations 459 93 280 1 833 Interest expense, net of interest income 468 Debt modification and extinguishment costs and other (income) expense, net 40 Income before income taxes $ 325 _________ (1) Includes $40 million and $ 41 million of lease levelization and $25 million and $ 4 million of amortization expense for the three months ended September 30, 2016 and 2015 , respectively. (2) Includes $(2) million and $ (1) million of lease levelization and $79 million and $ 11 million of amortization expense for the nine months ended September 30, 2016 and 2015 , respectively. |
Basis of Presentation and Sum31
Basis of Presentation and Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | |
Accounting Policies [Line Items] | |||||
Asset Impairment Charges | $ 0 | $ 0 | $ 0 | $ 0 | |
Gain on Business Interruption Insurance Recovery | 9 | 0 | 17 | 0 | |
Prior Period Reclassification Adjustment | $ 152 | ||||
Current | 210 | 210 | 216 | ||
Non-current | 15 | 15 | 12 | ||
Total | 225 | 225 | 228 | ||
Interest costs capitalized | 5 | $ 3 | 14 | $ 12 | |
Debt service | |||||
Accounting Policies [Line Items] | |||||
Current | 39 | 39 | 28 | ||
Non-current | 7 | 7 | 8 | ||
Total | 46 | 46 | 36 | ||
Construction major maintenance | |||||
Accounting Policies [Line Items] | |||||
Current | 34 | 34 | 50 | ||
Non-current | 4 | 4 | 2 | ||
Total | 38 | 38 | 52 | ||
Security project insurance | |||||
Accounting Policies [Line Items] | |||||
Current | 134 | 134 | 136 | ||
Non-current | 2 | 2 | 0 | ||
Total | 136 | 136 | 136 | ||
Other | |||||
Accounting Policies [Line Items] | |||||
Current | 3 | 3 | 2 | ||
Non-current | 2 | 2 | 2 | ||
Total | $ 5 | $ 5 | $ 4 | ||
Geothermal properties, gross [Member] | Minimum [Member] | |||||
Accounting Policies [Line Items] | |||||
Property, plant and equipment, estimated useful lives | 13 years | ||||
Geothermal properties, gross [Member] | Maximum [Member] | |||||
Accounting Policies [Line Items] | |||||
Property, plant and equipment, estimated useful lives | 58 years | ||||
Property, plant and equipment, other types [Member] | Minimum [Member] | |||||
Accounting Policies [Line Items] | |||||
Property, plant and equipment, estimated useful lives | 3 years | ||||
Property, plant and equipment, other types [Member] | Maximum [Member] | |||||
Accounting Policies [Line Items] | |||||
Property, plant and equipment, estimated useful lives | 46 years | ||||
Building, machinery and equipment, gross [Member] | Minimum [Member] | |||||
Accounting Policies [Line Items] | |||||
Property, plant and equipment, estimated useful lives | 3 years | ||||
Building, machinery and equipment, gross [Member] | Maximum [Member] | |||||
Accounting Policies [Line Items] | |||||
Property, plant and equipment, estimated useful lives | 46 years |
Basis of Presentation and Sum32
Basis of Presentation and Summary of Significant Accounting Policies Property, Plant and Equipment, Net (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Property, Plant and Equipment [Line Items] | ||
Buildings, machinery and equipment | $ 16,478 | $ 16,294 |
Geothermal properties | 1,376 | 1,319 |
Other | 228 | 208 |
Property, plant and equipment, gross | 18,082 | 17,821 |
Less: Accumulated depreciation | 5,719 | 5,377 |
Property, plant and equipment, gross, less accumulated depreciation, depletion and amortization | 12,363 | 12,444 |
Land | 119 | 120 |
Construction in progress | 587 | 448 |
Property, plant and equipment, net | $ 13,069 | $ 13,012 |
Acquisition (Details)
Acquisition (Details) | 3 Months Ended | |||||||||
Dec. 31, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2014USD ($) | Oct. 26, 2016MW | Oct. 09, 2016USD ($) | Sep. 30, 2016USD ($) | Apr. 01, 2016USD ($)MW | Feb. 05, 2016USD ($)MW | Dec. 31, 2015USD ($) | Oct. 01, 2015USD ($) | |
Business Acquisition [Line Items] | ||||||||||
Current assets held for sale | $ 452,000,000 | $ 0 | ||||||||
Granite Ridge Energy Center [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Business combination, recognized identifiable assets acquired and liabilities assumed, net | $ 500,000,000 | |||||||||
Power generation capacity | MW | 745 | |||||||||
Summer Peaking Capacity | MW | 695 | |||||||||
Crane Champion Holdco, LLC [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Ownership percentage of acquiree | 75.00% | |||||||||
EDF Trading North America, LLC [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Ownership percentage of acquiree | 25.00% | |||||||||
Champion Energy Marketing, LLC [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Business combination, recognized identifiable assets acquired and liabilities assumed, net | $ 240,000,000 | |||||||||
South Point Energy Center [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proceeds from Sale of Productive Assets | $ 76,000,000 | |||||||||
Net present value of transmission capacity payment obligations | $ 112,000,000 | |||||||||
Remaining tribal lease costs | 9,000,000 | |||||||||
Near-term repairs, maintenance and capital improvements to restore the power plant to full capacity | $ 21,000,000 | |||||||||
Summer Peaking Capacity | MW | 504 | |||||||||
Osprey Energy Center [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proceeds from Sale of Productive Assets | $ 166,000,000 | |||||||||
Osprey Energy Center Agreement Term | 27 months | |||||||||
Subsequent Event [Member] | NAES [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Business combination, recognized identifiable assets acquired and liabilities assumed, net | $ 800,000,000 | |||||||||
Working Capital Adjustment to Sale Price | $ 100,000,000 | |||||||||
Expected recovery through collateral synergies | $ 200,000,000 | |||||||||
Number of States in which Entity Operates | 18 | |||||||||
Subsequent Event [Member] | Mankato [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proceeds from Sale of Productive Assets | 396,000,000 | |||||||||
Gain (Loss) on Sale of Assets and Asset Impairment Charges | $ 160,000,000 | |||||||||
Power generation capacity | MW | 375 | |||||||||
Expansion generation capacity | MW | 345 | |||||||||
Other Current Assets [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Current assets held for sale | 12,000,000 | |||||||||
Property, Plant and Equipment [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Current assets held for sale | 401,000,000 | |||||||||
Other Assets [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Current assets held for sale | $ 39,000,000 |
Variable Interest Entities an34
Variable Interest Entities and Unconsolidated Investments in Power Plants (Unconsolidated VIEs) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | $ 80 | $ 79 |
Greenfield [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | $ 70 | 65 |
Equity method investment, ownership percentage | 50.00% | |
Whitby [Member] | ||
Schedule of Equity Method Investments [Line Items] | ||
Equity method investments | $ 10 | $ 14 |
Equity method investment, ownership percentage | 50.00% |
Variable Interest Entities an35
Variable Interest Entities and Unconsolidated Investments in Power Plants (Income from Unconsolidated Investments 10-Q) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
(Income) from unconsolidated investments in power plants | $ (6) | $ (6) | $ (16) | $ (18) |
Greenfield [Member] | ||||
(Income) from unconsolidated investments in power plants | (3) | (3) | (8) | (9) |
Whitby [Member] | ||||
(Income) from unconsolidated investments in power plants | $ (3) | $ (3) | $ (8) | $ (9) |
Variable Interest Entities an36
Variable Interest Entities and Unconsolidated Investments in Power Plants (VIE Texuals) (Details) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016USD ($)MW | Sep. 30, 2015USD ($) | Sep. 30, 2016USD ($)MW | Sep. 30, 2015USD ($) | Dec. 31, 2015USD ($)MW | |
Variable Interest Entity [Line Items] | |||||
Variable interest entity, financial or other support, amount | $ 1 | $ 2 | $ 1 | $ 2 | |
Equity method investment, summarized financial information, debt | 270 | 270 | $ 269 | ||
Prorata share of equity method investment, summarized financial information, debt | $ 135 | $ 135 | $ 135 | ||
Greenfield [Member] | |||||
Variable Interest Entity [Line Items] | |||||
Power generation capacity | MW | 1,038 | 1,038 | |||
Equity method investment, ownership percentage | 50.00% | 50.00% | |||
Distribution from equity method investee | $ 1 | 10 | $ 6 | 10 | |
Whitby [Member] | |||||
Variable Interest Entity [Line Items] | |||||
Power generation capacity | MW | 50 | 50 | |||
Equity method investment, ownership percentage | 50.00% | 50.00% | |||
Distribution from equity method investee | $ 0 | $ 0 | $ 13 | $ 13 | |
Variable Interest Entity, Primary Beneficiary [Member] | |||||
Variable Interest Entity [Line Items] | |||||
Power generation capacity | MW | 10,266 | 10,266 | 10,266 |
Debt (Debt) (Details)
Debt (Debt) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | $ 11,820 | $ 11,937 |
Debt, Current | 197 | 221 |
Long-term Debt, Excluding Current Maturities | 11,623 | 11,716 |
Unsecured Debt [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 3,410 | 3,406 |
Loans Payable [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 2,637 | 3,277 |
Corporate Debt Securities [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 2,408 | 1,789 |
Notes Payable, Other Payables [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 1,628 | 1,715 |
Secured Debt [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | 1,556 | 1,565 |
Capital Lease Obligations [Member] | ||
Debt Instrument [Line Items] | ||
Debt and Capital Lease Obligations | $ 181 | $ 185 |
Debt Senior Unsecured Notes (De
Debt Senior Unsecured Notes (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | ||
Long-term Debt | $ 11,802 | $ 11,292 |
Senior Unsecured Notes 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt | 1,236 | 1,235 |
Senior Unsecured Notes 2024 [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt | 642 | 641 |
Senior Unsecured Notes 2025 [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt | 1,532 | 1,530 |
Unsecured Debt [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt | $ 3,410 | $ 3,406 |
Debt (First Lien Term Loans) (D
Debt (First Lien Term Loans) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||||
Sep. 30, 2016 | Jun. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | May 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 11,802 | $ 11,802 | $ 11,292 | ||||
Gain (Loss) on Extinguishment of Debt | 0 | $ 0 | (15) | $ (32) | |||
First Lien Term Loan 2019 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | 0 | 0 | 795 | ||||
2020 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | 0 | 0 | 378 | ||||
2022 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | 1,562 | 1,562 | 1,571 | ||||
2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | 530 | 530 | 533 | ||||
New 2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Face Amount | $ 562 | ||||||
Long-term Debt | 545 | 545 | 0 | ||||
Debt Instrument Unamortized Discount Percent | 1.00% | ||||||
Debt Issuance Costs, Net | $ 11 | ||||||
First Lien Term Loans [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Long-term Debt | $ 2,637 | $ 2,637 | $ 3,277 | ||||
2019 and 2020 First Lien Term Loans [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Gain (Loss) on Extinguishment of Debt | $ 15 | ||||||
Federal Funds Effective Rate [Member] | New 2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 0.50% | ||||||
Eurodollar Rate For A One-Month Interest Period [Member] | New 2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | ||||||
Prime Rate or The Eurodollar Rate For A One-Month Interest Period [Member] | New 2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | ||||||
London Interbank Offered Rate (LIBOR) [Member] | New 2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Basis Spread on Variable Rate | 3.00% | ||||||
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | New 2023 First Lien Term Loan [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 0.00% |
Debt (First Lien Notes) (Detail
Debt (First Lien Notes) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | May 31, 2016 | Dec. 31, 2015 |
Debt Instrument [Line Items] | |||
Long-term Debt | $ 11,802 | $ 11,292 | |
2022 First Lien Notes [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 739 | 737 | |
First Lien Notes 2023 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 569 | 568 | |
2024 First Lien Notes [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 484 | 484 | |
2026 First Lien Notes [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Face Amount | $ 625 | ||
Long-term Debt | 616 | 0 | |
Debt Instrument, Interest Rate, Stated Percentage | 5.25% | ||
Debt Issuance Costs, Net | $ 9 | ||
Corporate Debt Securities [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 2,408 | $ 1,789 |
Debt (Letter of Credit) (Detail
Debt (Letter of Credit) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 | |
Line of Credit Facility [Line Items] | |||
Letters of Credit Outstanding, Amount | $ 761 | $ 755 | |
Corporate Revolving Credit Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Letters of Credit Outstanding, Amount | [1] | 268 | 316 |
CDH [Member] | |||
Line of Credit Facility [Line Items] | |||
Letters of Credit Outstanding, Amount | 261 | 241 | |
Various Project Financing Facilities [Member] | |||
Line of Credit Facility [Line Items] | |||
Letters of Credit Outstanding, Amount | $ 232 | $ 198 | |
[1] | The Corporate Revolving Facility represents our primary revolving facility. |
Debt (Fair Value of Debt) (Deta
Debt (Fair Value of Debt) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | $ 11,802 | $ 11,292 | |
Unsecured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,410 | 3,406 | |
Loans Payable [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,637 | 3,277 | |
Corporate Debt Securities [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,408 | 1,789 | |
Reported Value Measurement [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 11,548 | 11,645 | |
Reported Value Measurement [Member] | Unsecured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,410 | 3,406 | |
Reported Value Measurement [Member] | Loans Payable [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,637 | 3,277 | |
Reported Value Measurement [Member] | Corporate Debt Securities [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,408 | 1,789 | |
Reported Value Measurement [Member] | Notes Payable, Other Payable excluding Capital Leases [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | [1] | 1,537 | 1,608 |
Reported Value Measurement [Member] | Secured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 1,556 | 1,565 | |
Fair Value, Inputs, Level 2 [Member] | Unsecured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 3,429 | 3,063 | |
Fair Value, Inputs, Level 2 [Member] | Loans Payable [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,694 | 3,197 | |
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 2,537 | 1,885 | |
Fair Value, Inputs, Level 2 [Member] | Secured Debt [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | 1,566 | 1,494 | |
Fair Value, Inputs, Level 3 [Member] | Notes Payable, Other Payable excluding Capital Leases [Member] | |||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |||
Long-term Debt | [1] | $ 1,576 | $ 1,653 |
[1] | Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP. |
Debt (Debt Textuals) (Details)
Debt (Debt Textuals) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2016 | Feb. 08, 2016 | Sep. 30, 2015 | |
Debt Instruments [Abstract] | |||||
Prior Period Reclassification Adjustment | $ 152 | ||||
Debt Instrument, Interest Rate, Effective Percentage | 5.50% | 5.70% | |||
Corporate Revolving Credit Facility [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Line of Credit Facility, Increase (Decrease), Net | $ 178 | ||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 1,678 | ||||
Future line of credit facility maximum borrowing capacity on June 27, 2018 | $ 1,520 | ||||
Increase in Letter of Credit Sublimit | 250 | ||||
Total Letter of Credit Sublimit | $ 1,000 | ||||
Extension of Line of Credit Revolver | 2 years |
Assets and Liabilities with R44
Assets and Liabilities with Recurring Fair Value Measurements Fair Value Hierarchy (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash equivalents | [1] | $ 786 | $ 1,134 |
Margin deposits | [2] | 120 | 89 |
Commodity futures contracts | 1,036 | 1,736 | |
Commodity forward contracts | [3] | 238 | 274 |
Interest Rate Derivative Assets, Fair Value | 8 | 1 | |
Total assets | 2,188 | 3,234 | |
Margin deposits held by us posted by our counterparties | [2],[4] | 30 | 35 |
Commodity futures contracts | 1,004 | 1,604 | |
Commodity forward contracts | [3] | 342 | 513 |
Interest Rate Derivative Liabilities At Fair Value | 81 | 90 | |
Liabilities, Fair Value Disclosure | 1,457 | 2,242 | |
Fair Value, Inputs, Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash equivalents | [1] | 786 | 1,134 |
Margin deposits | 120 | 89 | |
Commodity futures contracts | 1,036 | 1,736 | |
Commodity forward contracts | [3] | 0 | 0 |
Interest Rate Derivative Assets, Fair Value | 0 | 0 | |
Total assets | 1,942 | 2,959 | |
Margin deposits held by us posted by our counterparties | 30 | 35 | |
Commodity futures contracts | 1,004 | 1,604 | |
Commodity forward contracts | [3] | 0 | 0 |
Interest Rate Derivative Liabilities At Fair Value | 0 | 0 | |
Liabilities, Fair Value Disclosure | 1,034 | 1,639 | |
Fair Value, Inputs, Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash equivalents | [1] | 0 | 0 |
Margin deposits | 0 | 0 | |
Commodity futures contracts | 0 | 0 | |
Commodity forward contracts | [3] | 178 | 220 |
Interest Rate Derivative Assets, Fair Value | 8 | 1 | |
Total assets | 186 | 221 | |
Margin deposits held by us posted by our counterparties | 0 | 0 | |
Commodity futures contracts | 0 | 0 | |
Commodity forward contracts | [3] | 310 | 413 |
Interest Rate Derivative Liabilities At Fair Value | 81 | 90 | |
Liabilities, Fair Value Disclosure | 391 | 503 | |
Fair Value, Inputs, Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash equivalents | [1] | 0 | 0 |
Margin deposits | 0 | 0 | |
Commodity futures contracts | 0 | 0 | |
Commodity forward contracts | [3] | 60 | 54 |
Interest Rate Derivative Assets, Fair Value | 0 | 0 | |
Total assets | 60 | 54 | |
Margin deposits held by us posted by our counterparties | 0 | 0 | |
Commodity futures contracts | 0 | 0 | |
Commodity forward contracts | [3] | 32 | 100 |
Interest Rate Derivative Liabilities At Fair Value | 0 | 0 | |
Liabilities, Fair Value Disclosure | $ 32 | $ 100 | |
[1] | As of September 30, 2016 and December 31, 2015, we had cash equivalents of $561 million and $906 million included in cash and cash equivalents and $225 million and $228 million included in restricted cash, respectively. | ||
[2] | Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements. | ||
[3] | Includes OTC swaps and options. | ||
[4] | Included in other current liabilities on our Consolidated Condensed Balance Sheets. |
Assets and Liabilities with R45
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) - USD ($) | Sep. 30, 2016 | Dec. 31, 2015 |
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Derivative, Fair Value, Net | $ (145,000,000) | $ (196,000,000) |
Power Contracts [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Derivative, Fair Value, Net | 7,000,000 | (54,000,000) |
Power Contracts [Member] | Minimum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs Quantitative Information | 9.62 | 6.72 |
Power Contracts [Member] | Maximum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs Quantitative Information | 80.18 | 83.25 |
Natural Gas [Member] | Minimum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs Quantitative Information | ||
Natural Gas [Member] | Maximum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs Quantitative Information | ||
Power Congestion Products [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Derivative, Fair Value, Net | 12,000,000 | 8,000,000 |
Power Congestion Products [Member] | Minimum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs Quantitative Information | (11.47) | (11.47) |
Power Congestion Products [Member] | Maximum [Member] | ||
Fair Value Inputs, Assets, Quantitative Information [Line Items] | ||
Fair Value Inputs Quantitative Information | $ 10.89 | $ 12.19 |
Assets and Liabilities with R46
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | ||
Fair Value Measurement [Domain] | |||||||
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract] | |||||||
Cash and Cash Equivalents, at Carrying Value | $ 561 | $ 561 | $ 906 | ||||
Restricted Cash and Cash Equivalents | 225 | 225 | 228 | ||||
Balance, beginning of period | (63) | $ 243 | (46) | $ 85 | |||
Included in operating revenues | [1] | 30 | 70 | 9 | 236 | ||
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense | [2] | (31) | (2) | (24) | (2) | ||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases | 1 | 0 | 4 | 3 | |||
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements | 15 | (8) | (4) | (24) | |||
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount | 0 | 0 | 0 | 0 | |||
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount | 0 | 0 | 0 | 0 | |||
Transfers into level 3 | [3],[4] | 1 | 0 | 0 | 0 | ||
Transfers out of Level 3 | [4],[5] | 75 | (11) | 89 | (6) | ||
Balance, end of period | 28 | 292 | 28 | 292 | |||
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss) | (1) | 68 | (15) | 234 | |||
Cash and Cash Equivalents, at Carrying Value | 561 | $ 659 | 561 | $ 659 | 906 | $ 717 | |
Restricted Cash and Cash Equivalents | $ 225 | $ 225 | $ 228 | ||||
[1] | For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations. | ||||||
[2] | For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations. | ||||||
[3] | We had $1 million and nil in gains transferred out of level 2 into level 3 for the three months ended September 30, 2016 and 2015, respectively. There were no transfers out of level 2 into level 3 for each of the nine months ended September 30, 2016 and 2015. | ||||||
[4] | We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three and nine months ended September 30, 2016 and 2015. | ||||||
[5] | We had $(75) million in losses and $11 million in gains transferred out of level 3 into level 2 for the three months ended September 30, 2016 and 2015, respectively, and $(89) million in losses and $6 million in gains transferred out of level 3 into level 2 for the nine months ended September 30, 2016 and 2015, respectively, due to changes in market liquidity in various power markets. |
Derivative Instruments (Details
Derivative Instruments (Details) $ in Millions | 9 Months Ended | 12 Months Ended | ||
Sep. 30, 2016USD ($)MWhMMBTUt | Dec. 31, 2014MWhMMBTUt | Dec. 31, 2015USD ($) | ||
Power [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh | (49) | (41) | ||
Natural Gas [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU | 846 | 996 | ||
Environmental Credits [Member] | ||||
Derivative [Line Items] | ||||
Derivative, Nonmonetary Notional Amount, Mass | t | 17 | 8 | ||
Interest Rate Hedging Instruments | ||||
Derivative [Line Items] | ||||
Derivative, Notional Amount | $ | $ 3,791 | [1] | $ 1,320 | |
[1] | We entered into interest rate hedging instruments during the second quarter of 2016 to hedge approximately $2.5 billion of variable rate corporate debt for 2017 through 2019 which effectively places a ceiling on LIBOR at rates varying from 1.44% to 1.8125% for hedged interest payments. See Note 4 for a further discussion of our First Lien Term Loans. |
Derivative Instruments (Detai48
Derivative Instruments (Details 2) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets, current | $ 959 | $ 1,698 |
Long-term derivative assets | 323 | 313 |
Total derivative assets | 1,282 | 2,011 |
Derivative liabilities, current | 991 | 1,734 |
Long-term derivative liabilities | 436 | 473 |
Total derivative liabilities | 1,427 | 2,207 |
Derivative, Fair Value, Net | (145) | (196) |
Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total derivative assets | 8 | 1 |
Total derivative liabilities | 81 | 90 |
Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total derivative assets | 1,274 | 2,010 |
Total derivative liabilities | 1,346 | 2,117 |
Interest Rate Hedging Instruments | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, current | 0 | 0 |
Derivative Assets, Noncurrent | 8 | 1 |
Total derivative assets | 8 | 1 |
Current derivative liabilities | 33 | 37 |
Derivative Liabilities, Noncurrent | 48 | 53 |
Total derivative liabilities | 81 | 90 |
Derivative, Fair Value, Net | (73) | (89) |
Interest Rate Hedging Instruments | Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total derivative assets | 8 | 1 |
Total derivative liabilities | 81 | 90 |
Energy Related Derivative [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets, current | 959 | 1,698 |
Derivative Assets, Noncurrent | 315 | 312 |
Total derivative assets | 1,274 | 2,010 |
Current derivative liabilities | 958 | 1,697 |
Derivative Liabilities, Noncurrent | 388 | 420 |
Total derivative liabilities | 1,346 | 2,117 |
Derivative, Fair Value, Net | (72) | (107) |
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total derivative assets | 1,274 | 2,010 |
Total derivative liabilities | $ 1,346 | $ 2,117 |
Derivative Instruments (Detail
Derivative Instruments (Detail 3) (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 | |
Derivative Instruments Subject to Master Netting Arrangement [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | $ 1,282 | $ 2,011 | |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (1,116) | (1,804) | |
Derivative, Collateral, Obligation to Return Cash | [1] | (65) | (137) |
Derivative Liability, Fair Value, Gross Liability | (1,427) | (2,207) | |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 1,116 | 1,804 | |
Derivative, Collateral, Right to Reclaim Cash | [1] | 16 | 5 |
Derivative, Fair Value, Net | (145) | (196) | |
Derivative Fair Value, Amount Not Offset Against Collateral, Net | 0 | 0 | |
Margin/Cash (Received) Posted Subject to Master Netting Arrangement | [1] | (49) | (132) |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 101 | 70 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | (295) | (398) | |
Derivative, Fair Value, Amount Offset Against Collateral, Net | (194) | (328) | |
Commodity Exchange Traded Futures and Swaps Contracts [Member] | |||
Derivative Instruments Subject to Master Netting Arrangement [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 1,036 | 1,736 | |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (988) | (1,602) | |
Derivative, Collateral, Obligation to Return Cash | [1] | (48) | (134) |
Derivative Liability, Fair Value, Gross Liability | (1,004) | (1,604) | |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 988 | 1,602 | |
Derivative, Collateral, Right to Reclaim Cash | [1] | 16 | 2 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 0 | 0 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | 0 | 0 | |
Commodity Forward Contract [Member] | |||
Derivative Instruments Subject to Master Netting Arrangement [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 238 | 274 | |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | (128) | (202) | |
Derivative, Collateral, Obligation to Return Cash | [1] | (17) | (3) |
Derivative Liability, Fair Value, Gross Liability | (342) | (513) | |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 128 | 202 | |
Derivative, Collateral, Right to Reclaim Cash | [1] | 0 | 3 |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 93 | 69 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | (214) | (308) | |
Interest Rate Hedging Instruments | |||
Derivative Instruments Subject to Master Netting Arrangement [Line Items] | |||
Derivative Asset, Fair Value, Gross Asset | 8 | 1 | |
Derivative Asset, Fair Value, Amount Not Offset Against Collateral | 0 | 0 | |
Derivative, Collateral, Obligation to Return Cash | [1] | 0 | 0 |
Derivative Liability, Fair Value, Gross Liability | (81) | (90) | |
Derivative Liability, Fair Value, Amount Not Offset Against Collateral | 0 | 0 | |
Derivative, Collateral, Right to Reclaim Cash | [1] | 0 | 0 |
Derivative, Fair Value, Net | (73) | (89) | |
Derivative Asset, Fair Value, Amount Offset Against Collateral | 8 | 1 | |
Derivative Liability, Fair Value, Amount Offset Against Collateral | $ (81) | $ (90) | |
[1] | Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral. |
Derivative Instruments (Detai50
Derivative Instruments (Details 4) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Summary of Derivative Instruments by Risk Exposure [Abstract] | |||||
Power contracts included in operating revenues | $ 2,355 | $ 1,948 | $ 5,134 | $ 5,036 | |
Natural gas contracts included in fuel and purchased energy expense | 1,472 | 1,073 | 3,140 | 2,849 | |
Interest expense | 158 | 159 | 472 | 471 | |
Gain (Loss) on Derivative Instruments, Net, Pretax | 141 | 86 | 192 | 319 | |
Gain (Loss) on Sale of Derivatives | [1],[2] | 32 | 160 | 213 | 323 |
Mark-to-market gain (loss) | [3] | 109 | (74) | (21) | (4) |
Power [Member] | |||||
Summary of Derivative Instruments by Risk Exposure [Abstract] | |||||
Power contracts included in operating revenues | [1],[2] | 308 | 189 | 240 | 423 |
Interest Rate Contract [Member] | |||||
Summary of Derivative Instruments by Risk Exposure [Abstract] | |||||
Interest expense | [3] | 0 | 1 | 1 | 2 |
Mark-to-market gain (loss) | [3] | 0 | 1 | 1 | 2 |
Energy Related Derivative [Member] | |||||
Summary of Derivative Instruments by Risk Exposure [Abstract] | |||||
Gain (Loss) on Sale of Derivatives | [1],[2] | 32 | 160 | 213 | 323 |
Mark-to-market gain (loss) | [3] | 109 | (75) | (22) | (6) |
Natural Gas [Member] | |||||
Summary of Derivative Instruments by Risk Exposure [Abstract] | |||||
Natural gas contracts included in fuel and purchased energy expense | [1],[2] | $ (167) | $ (104) | $ (49) | $ (106) |
[1] | Does not include the realized value associated with derivative instruments that settle through physical delivery. | ||||
[2] | Includes amortization of acquisition date fair value of derivative activity related to the acquisition of Champion Energy. | ||||
[3] | In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. |
Derivative Instruments (Detai51
Derivative Instruments (Details 5) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | ||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Interest expense | $ 158 | $ 159 | $ 472 | $ 471 | |
Interest Rate Hedging Instruments | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net | [1],[2] | 18 | (4) | 0 | 4 |
Interest expense | [3] | 0 | 1 | 1 | 2 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Hedging Instruments | |||||
Derivative Instruments, Gain (Loss) [Line Items] | |||||
Interest expense | [1],[2],[4],[5] | $ (11) | $ (12) | $ (33) | $ (36) |
[1] | We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and nine months ended September 30, 2016 and 2015. | ||||
[2] | We recorded an income tax expense of nil for each of the three and nine months ended September 30, 2016 and 2015, in AOCI related to our cash flow hedging activities. | ||||
[3] | In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure. | ||||
[4] | Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $127 million and $127 million at September 30, 2016 and December 31, 2015, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $11 million and $11 million at September 30, 2016 and December 31, 2015, respectively. | ||||
[5] | Includes a loss of $1 million for each of the three and nine months ended September 30, 2016, that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur. |
Derivative Instruments (Textual
Derivative Instruments (Textuals) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Jun. 30, 2016 | Dec. 31, 2015 | |
Derivatives, Fair Value [Line Items] | ||||||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax | $ 0 | $ 0 | $ 0 | $ 0 | ||
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net | 1 | $ 1 | ||||
Summary of Derivative Instruments [Abstract] | ||||||
Maximum length of time hedging using interest rate derivative instruments | 7 years | |||||
Derivative, Net Liability Position, Aggregate Fair Value | 4 | $ 4 | ||||
Collateral Already Posted, Aggregate Fair Value | 1 | 1 | ||||
Additional Collateral, Aggregate Fair Value | 4 | 4 | ||||
Cash Flow Hedge (Gain) Loss to be Reclassified within Twelve Months | 39 | |||||
Parent [Member] | ||||||
Derivatives, Fair Value [Line Items] | ||||||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | 127 | 127 | $ 127 | |||
Noncontrolling Interest [Member] | ||||||
Derivatives, Fair Value [Line Items] | ||||||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | $ 11 | $ 11 | $ 11 | |||
Interest Rate Hedging Instruments | ||||||
Derivatives, Fair Value [Line Items] | ||||||
Derivative, Amount of Hedged Item | $ 2,500 | |||||
Interest Rate Cap Redemption Period 1 | ||||||
Derivatives, Fair Value [Line Items] | ||||||
Derivative, Cap Interest Rate | 1.44% | |||||
Interest Rate Cap Redemption Period 2 | ||||||
Derivatives, Fair Value [Line Items] | ||||||
Derivative, Cap Interest Rate | 1.8125% |
Use of Collateral (Details)
Use of Collateral (Details) - USD ($) $ in Millions | Sep. 30, 2016 | Dec. 31, 2015 | |
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
Margin deposits | [1] | $ 120 | $ 89 |
Natural gas and power prepayments | 27 | 34 | |
Total margin deposits and natural gas and power prepayments with our counterparties | [2] | 147 | 123 |
Letters of credit issued | 586 | 600 | |
First priority liens under power and natural gas agreements | [3] | 299 | 382 |
First priority liens under interest rate hedging instruments | 83 | 92 | |
Total letters of credit and first priority liens with our counterparties | 968 | 1,074 | |
Margin deposits held by us posted by our counterparties | [1],[4] | 30 | 35 |
Letters of credit posted with us by our counterparties | 35 | 24 | |
Total margin deposits and letters of credit posted with us by our counterparties | 65 | 59 | |
Use of Collateral (Textuals) [Abstract] | |||
Margin And Prepayment Amounts Included In Other Assets | 9 | 22 | |
Margin And Prepayment Amounts Included In Margin Deposits And Other Prepaid Expenses | 138 | 101 | |
Champion Energy [Member] | |||
Financial Instruments Owned and Pledged as Collateral [Line Items] | |||
First priority liens under power and natural gas agreements | $ 268 | $ 345 | |
[1] | Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements. | ||
[2] | At September 30, 2016 and December 31, 2015, $138 million and $101 million, respectively, were included in margin deposits and other prepaid expense and $9 million and $22 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets. | ||
[3] | Includes $268 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at September 30, 2016 and December 31, 2015, respectively. | ||
[4] | Included in other current liabilities on our Consolidated Condensed Balance Sheets. |
Income Taxes (Income Tax Expens
Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Income Tax Contingency [Line Items] | ||||
Income tax (expense) benefit | $ 4 | $ (28) | $ (17) | $ (32) |
Effective Income Tax Rate, Continuing Operations | (1.00%) | 9.00% | 20.00% | 10.00% |
Income Tax Uncertainties [Abstract] | ||||
Unrecognized Tax Benefits | $ 58 | $ 58 | ||
Unrecognized Tax Benefits that Would Impact Effective Tax Rate | 18 | 18 | ||
Unrecognized Tax Benefit Related to Deferred Tax Asset | 40 | 40 | ||
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued | 13 | 13 | ||
Minimum [Member] | ||||
Income Tax Contingency [Line Items] | ||||
Decrease in Unrecognized Tax Benefits is Reasonably Possible | 0 | 0 | ||
Maximum [Member] | ||||
Income Tax Contingency [Line Items] | ||||
Decrease in Unrecognized Tax Benefits is Reasonably Possible | $ 19 | $ 19 |
Earnings (Loss) per Share Recon
Earnings (Loss) per Share Reconciliation of Basic to Diluted Weighted Average Shares Outstanding (Details) - shares shares in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Earnings (Loss) per Share [Abstract] | ||||
Weighted Average Number of Shares Outstanding, Basic | 354,215 | 355,443 | 353,929 | 365,053 |
Weighted Average Number Diluted Shares Outstanding Adjustment | 2,137 | 2,233 | 2,051 | 3,166 |
Weighted Average Number of Shares Outstanding, Diluted | 356,352 | 357,676 | 355,980 | 368,219 |
Earnings (Loss) per Share (Deta
Earnings (Loss) per Share (Details) - shares shares in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Earnings Per Share [Abstract] | ||||
Share-based awards | 1,610 | 4,982 | 1,679 | 4,208 |
Stock-Based Compensation (Summa
Stock-Based Compensation (Summary restricted stock and restricted stock unit activity) (Details) - Restricted Stock [Member] - $ / shares | 9 Months Ended | |
Sep. 30, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | 4,955,244 | 3,528,270 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 15.84 | $ 19.91 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 2,947,826 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ 12.40 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period | 218,932 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ 16.21 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | 1,301,920 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ 19.02 |
Stock-Based Compensation (Stock
Stock-Based Compensation (Stock Based Compensation Textuals) (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Allocated Share-based Compensation Expense | $ 7 | $ 8 | $ 22 | $ 24 |
Allocated Share Based Compensation Expense Liability Classified Share-Based Awards | (1) | $ (1) | 1 | (5) |
Restricted Stock [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $ 31 | 31 | ||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition | 1 year 4 months 24 days | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value | $ 16 | $ 34 |
Stock-Based Compensation Liabil
Stock-Based Compensation Liability Based Stock Compensation (Details) - Performance Shares [Member] - $ / shares | 9 Months Ended | ||
Sep. 30, 2016 | Dec. 31, 2015 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number | 1,172,464 | 517,906 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ 18.56 | $ 23.36 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | 657,807 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ 14.81 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | [1] | 3,249 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ 23.91 | ||
[1] | In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date. |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | $ 2,355 | $ 1,948 | $ 5,134 | $ 5,036 | ||||
Commodity Margin | 820 | 974 | 2,057 | 2,166 | ||||
Add: Mark-to-market commodity activity, net and other | 63 | [1] | (99) | [1] | (63) | [2] | 21 | [2] |
Plant operating expense | 215 | 200 | 741 | 732 | ||||
Depreciation and amortization expense | 161 | 166 | 503 | 484 | ||||
Sales, general and other administrative expense | 33 | 33 | 106 | 100 | ||||
Other operating expenses | 18 | 16 | 55 | 56 | ||||
(Income) loss from unconsolidated investments in power plants | (6) | (6) | (16) | (18) | ||||
Income from operations | 462 | 466 | 605 | 833 | ||||
Interest expense, net of interest income | 157 | 158 | 469 | 468 | ||||
Debt Extinguishment Costs and Other (Income) Expense, Net | 8 | 1 | 36 | 40 | ||||
Income before income taxes | 297 | 307 | 100 | 325 | ||||
Lease levelization | 40 | 41 | (2) | (1) | ||||
Amortization of Intangible Assets | 25 | 4 | 79 | 11 | ||||
West [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 525 | 737 | 1,163 | 1,675 | ||||
Commodity Margin | 298 | 385 | 749 | 843 | ||||
Add: Mark-to-market commodity activity, net and other | 11 | [1] | 68 | [1] | (5) | [2] | 173 | [2] |
Plant operating expense | 79 | 87 | 268 | 313 | ||||
Depreciation and amortization expense | 56 | 61 | 181 | 193 | ||||
Sales, general and other administrative expense | 9 | 7 | 27 | 23 | ||||
Other operating expenses | 8 | 8 | 23 | 28 | ||||
(Income) loss from unconsolidated investments in power plants | 0 | 0 | 0 | 0 | ||||
Income from operations | 157 | 290 | 245 | 459 | ||||
Texas [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 1,070 | 713 | 2,139 | 1,872 | ||||
Commodity Margin | 198 | 264 | 511 | 583 | ||||
Add: Mark-to-market commodity activity, net and other | 110 | [1] | (98) | [1] | 7 | [2] | (47) | [2] |
Plant operating expense | 65 | 62 | 236 | 233 | ||||
Depreciation and amortization expense | 53 | 58 | 159 | 157 | ||||
Sales, general and other administrative expense | 13 | 15 | 43 | 47 | ||||
Other operating expenses | 2 | 2 | 6 | 6 | ||||
(Income) loss from unconsolidated investments in power plants | 0 | 0 | 0 | 0 | ||||
Income from operations | 175 | 29 | 74 | 93 | ||||
East [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 766 | 506 | 1,855 | 1,511 | ||||
Commodity Margin | 324 | 325 | 797 | 740 | ||||
Add: Mark-to-market commodity activity, net and other | (51) | [1] | (62) | [1] | (44) | [2] | (84) | [2] |
Plant operating expense | 78 | 57 | 258 | 206 | ||||
Depreciation and amortization expense | 52 | 48 | 163 | 135 | ||||
Sales, general and other administrative expense | 12 | 10 | 36 | 29 | ||||
Other operating expenses | 7 | 8 | 27 | 24 | ||||
(Income) loss from unconsolidated investments in power plants | (6) | (6) | (16) | (18) | ||||
Income from operations | 130 | 146 | 285 | 280 | ||||
Consolidation, Eliminations [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | (6) | (8) | (23) | (22) | ||||
Commodity Margin | 0 | 0 | 0 | 0 | ||||
Add: Mark-to-market commodity activity, net and other | (7) | [1] | (7) | [1] | (21) | [2] | (21) | [2] |
Plant operating expense | (7) | (6) | (21) | (20) | ||||
Depreciation and amortization expense | 0 | (1) | 0 | (1) | ||||
Sales, general and other administrative expense | (1) | 1 | 0 | 1 | ||||
Other operating expenses | 1 | (2) | (1) | (2) | ||||
(Income) loss from unconsolidated investments in power plants | 0 | 0 | 0 | 0 | ||||
Income from operations | 0 | 1 | 1 | 1 | ||||
Operating Segments [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 2,355 | 1,948 | 5,134 | 5,036 | ||||
Operating Segments [Member] | West [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 524 | 736 | 1,159 | 1,672 | ||||
Operating Segments [Member] | Texas [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 1,067 | 709 | 2,129 | 1,860 | ||||
Operating Segments [Member] | East [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 764 | 503 | 1,846 | 1,504 | ||||
Operating Segments [Member] | Consolidation, Eliminations [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 0 | 0 | 0 | 0 | ||||
Intersegment Eliminations [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 0 | 0 | 0 | 0 | ||||
Intersegment Eliminations [Member] | West [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 1 | 1 | 4 | 3 | ||||
Intersegment Eliminations [Member] | Texas [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 3 | 4 | 10 | 12 | ||||
Intersegment Eliminations [Member] | East [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | 2 | 3 | 9 | 7 | ||||
Intersegment Eliminations [Member] | Consolidation, Eliminations [Member] | ||||||||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||||||||
Operating revenues | $ (6) | $ (8) | $ (23) | $ (22) | ||||
[1] | Includes $40 million and $41 million of lease levelization and $25 million and $4 million of amortization expense for the three months ended September 30, 2016 and 2015, respectively. | |||||||
[2] | Includes $(2) million and $(1) million of lease levelization and $79 million and $11 million of amortization expense for the nine months ended September 30, 2016 and 2015, respectively. |